Puc8292.v1.doc

1 BOISE, IDAHO, WEDNESDAY, AUGUST 29, 2001, 1:15 P. M.

2

3

4 COMMISSIONER KJELLANDER: We'll go back on

5 the record and when we left, Mr. Lord had been sworn in and

6 the testimony had been spread across the record and I

7 believe we are ready for cross with Idaho Power and

8 Mr. Ripley.

9 MR. RIPLEY: We have no questions.

10 COMMISSIONER KJELLANDER: You know, we could

11 have done that before lunch.

12 MR. RIPLEY: I didn't know that before lunch.

13 COMMISSIONER KJELLANDER: Okay, are there any

14 questions from the Commission?

15 COMMISSIONER HANSEN: Yeah, I've got a

16 couple.

17 COMMISSIONER KJELLANDER: You've got a couple

18 of questions? Okay, Commissioner Hansen.

19 COMMISSIONER HANSEN: I mean, Mr. Lord, you

20 came a long ways.

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CSB REPORTING COLLOQUY
Wilder, Idaho 83676

1 THOMAS J. LORD,

2 produced as a witness at the instance of the Staff, having

3 been previously duly sworn, resumed the stand and was

4 further examined and testified as follows:

5

6 EXAMINATION

7

8 BY COMMISSIONER HANSEN:

9 Q I guess just a couple of questions. On

10 page 2 of your testimony, lines 21 through 24, I take it

11 you're saying that Mr. Gale's testimony indicates that

12 Idaho Power won't be doing any real hedging for purchases

13 beyond 30 days in the future and I'm just kind of curious,

14 can you reference where Mr. Gale said that directly or are

15 you just assuming that's what he meant?

16 A Actually that has been clarified since is

17 that there was the possibility to infer that certain

18 hedging decisions, that it had changed. In discussions

19 with the Company since then and in response to Staff

20 questions, that has been clarified to -- and what I said

21 was that indicates I did not know whether that was or was

22 not. In response to Staff requests, that point has been

23 cleared up that yes, in certain circumstances long-term

24 hedging may occur.

25 Q Okay. On page 4, lines 10 and 11 of your

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CSB REPORTING LORD (Com)
Wilder, Idaho 83676 Staff

1 testimony, you note that the PCA is not an effective

2 hedging mechanism. Does it offer any protection against

3 price risk in your mind?

4 A No. All it does is spread the liability for

5 that price risk over a future period of time such that all

6 of the price risk is absorbed by the customer if the PCA is

7 fully authorized and subject to such things as the 90-10

8 sharing, but that portion of the price risk to which the

9 customers are exposed will be spread across a future period

10 and in essence levelized.

11 Q A couple more questions I had. Referring to

12 your testimony on page 19 and 20, can you help me

13 understand how IES can profit from knowledge of Idaho Power

14 Company's future actions?

15 A This is the, and the term I used was, front

16 running in markets where liquidity is constrained, that is,

17 markets where the amount of potential transactions exceed

18 the ability to transact at any given time without moving

19 the price of the market. In those type of markets knowing

20 when someone who will have to do large trades will have to

21 transact gives you a better concept of the likelihood of

22 price direction and therefore gives you a greater

23 probability of being correct in your speculative decisions

24 on which way the market price will move.

25 Q I see, and the last question is in reference

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CSB REPORTING LORD (Com)
Wilder, Idaho 83676 Staff

1 to page 21, lines 18 through 20, you say that hedging

2 activity by Idaho Power Company could reduce benefits to

3 IES, so are you saying that as Idaho Power Company expends

4 resources on hedging activities it would reduce the

5 benefits of IES?

6 A Assuming, and this is potential, this was

7 discussed in the context of what might occur, if that

8 knowledge, if you would, of when transactions will occur is

9 reduced by the hedging activities of IPC such that IPC does

10 not have to be in the market concurrently with IES, it is

11 possible that that would reduce IES's ability to forecast

12 potentially the direction of price.

13 Q So you're saying there could be a conflict

14 there?

15 A I'm saying that the hedging could in essence

16 reduce potentially that conflict.

17 Q I see.

18 A Assuming that they are actually acting in

19 that manner, which I said this was done in the context of

20 what could occur. The information is not there and has not

21 been presented to me to make any statement as to whether it

22 is occurring.

23 COMMISSIONER HANSEN: Thank you. That's all

24 the questions I have, Mr. Chairman.

25 COMMISSIONER SMITH: Mr. Chairman?

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CSB REPORTING LORD (Com)
Wilder, Idaho 83676 Staff

1 COMMISSIONER KJELLANDER: Commissioner Smith.

2 COMMISSIONER SMITH: I just wanted to clarify

3 that you will be here for the -16 case?

4 THE WITNESS: Yes.

5 COMMISSIONER SMITH: Thank you.

6 COMMISSIONER KJELLANDER: That moves us to

7 redirect.

8

9 REDIRECT EXAMINATION

10

11 BY MS. NORDSTROM:

12 Q Mr. Lord, you indicated when you were being

13 sworn in that your answers to the questions that were posed

14 in your direct testimony were the same; is that correct?

15 A That is correct.

16 Q Why did you clarify that?

17 A Because --

18 MR. RIPLEY: Mr. Chairman, I'm going to ask

19 what redirect is this? There must be some grounds upon

20 which the redirect is founded upon, I assume the

21 cross-examination of the questions of Commissioner Hansen.

22 COMMISSIONER KJELLANDER: I would have to

23 concur that when we start to look at the purpose of

24 redirect that this seems to fall outside of that.

25 MS. NORDSTROM: Okay. I guess my thought was

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CSB REPORTING LORD (Di)
Wilder, Idaho 83676 Staff

1 that if his testimony is somehow changed in any way that

2 the Commission would want to be apprised of that, but if

3 that's not the case --

4 COMMISSIONER KJELLANDER: I would have

5 thought that that would have been in the introductory

6 remarks with the testimony.

7 MS. NORDSTROM: Well, because he clarified

8 his answer, that's what I was trying to explore.

9 MR. RIPLEY: We're happy with the way the

10 record is, Mr. Chairman.

11 COMMISSIONER KJELLANDER: That's fine. I

12 don't know that the clarification would really fit within

13 the boundaries of redirect.

14 MS. NORDSTROM: Okay.

15 Q BY MS. NORDSTROM: Commissioner Hansen spoke

16 of hedges. Is it your understanding or based on your

17 review of the internal policies and risk management

18 guidelines that govern Idaho Power, were all of the hedges

19 in conformance with those internal policies and guidelines?

20 A I believe not.

21 Q Would you elaborate?

22 A Specifically, the discussion that has

23 occurred that has been prefaced as a pricing practice, the

24 swap, in essence, that was discussed by Ms. Hoyd yesterday,

25 is actually a multi-period hedge. It is a transfer of

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CSB REPORTING LORD (Di)
Wilder, Idaho 83676 Staff

1 day-ahead pricing or real-time pricing to day-ahead

2 pricing, that is correct; however, as performed by the

3 Company, that has had a multi-month impact. Multi-month

4 hedges under the corporate policies and procedures require

5 Risk Management Committee approval.

6 We have no minutes and/or discussion from the

7 Risk Management Committee authorizing that transaction.

8 There is no paper trail, in essence, for the Staff to

9 review the decision process for that hedge. In essence,

10 that hedge would have required Risk Management Committee

11 approval, transmission of authorization to the trader and

12 trader execution. None of those have occurred. That swap

13 is, in essence, a transaction outside of corporate policies

14 and procedures.

15 Q Based on your review of these policies that

16 govern risk management, do you feel that adequate policies

17 and procedures were in place for management to properly

18 manage the customer's speculative position specifically by

19 the Risk Management Committee?

20 A I believe that the decisions of the Company

21 have been all directed towards the reliability of the

22 system. Reliability, in essence, is a volume obligation,

23 the obligation to serve. The purchased cost adjustment is

24 a mechanism by which the price at which the Company

25 transacts is transferred to the customers. The customers

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CSB REPORTING LORD (Di)
Wilder, Idaho 83676 Staff

1 therefore, in essence, have a speculative position which is

2 managed by the Company. By the Company saying we will look

3 at forward prices, but we will firmly and mainly direct our

4 decision process towards reliability, they said they have

5 minimized the discussion or at least not put forward as a

6 primary goal the discussion of managing that customer

7 speculative risk.

8 They have in the discussion talked about VAR

9 and CVAR which are the -- which says that they have

10 corporately on the nonregulated side certain processes for

11 determining the scope of risk based on forward market

12 volatilities, the expectation of the market of forward

13 price movements. That is what the calculation of VAR and

14 CVAR implies; therefore, there were members of the Risk

15 Management Committee that had experience in that type of

16 analysis.

17 That analysis has not been brought to bear

18 for the customers; therefore, it appears that the range of

19 risks for the customers was not considered when these

20 decisions were made and I feel that that does not, in

21 essence, give them the capability to make the best

22 decisions for the customer.

23 Q Mr. Lord, in your capacity as an advisor,

24 what types of entities do you advise typically?

25 MR. RIPLEY: Objection, it's far outside the

467

CSB REPORTING LORD (Di)
Wilder, Idaho 83676 Staff

1 range of redirect that I can see.

2 MS. NORDSTROM: I'll tie this back in to the

3 corporate policies and procedures we've been discussing.

4 MR. RIPLEY: Discussing when?

5 COMMISSIONER KJELLANDER: Why don't you tie

6 it in as a question that you're posing as opposed to tying

7 it in down the road.

8 Q BY MS. NORDSTROM: In comparison with other

9 utilities that you have advised on similar types of

10 policies and procedures by their respective risk management

11 committees, how would you assess Idaho Power's relative

12 position to these other utilities in adequately planning

13 for market changes that are currently transpiring?

14 MR. RIPLEY: Again, I will object it's

15 outside the scope of redirect.

16 COMMISSIONER KJELLANDER: And based on what

17 we've seen so far, I would have to concur that it is

18 outside of the redirect.

19 MS. NORDSTROM: No further questions.

20 COMMISSIONER KJELLANDER: Thank you. Thank

21 you.

22 THE WITNESS: Thank you.

23 (The witness left the stand.)

24 COMMISSIONER KJELLANDER: And does that

25 conclude Staff's witnesses?

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CSB REPORTING LORD (Di)
Wilder, Idaho 83676 Staff

1 MS. NORDSTROM: It does.

2 COMMISSIONER KJELLANDER: Okay. At this

3 point now we move towards the rebuttal side of the case

4 with Idaho Power and, Mr. Ripley, earlier you had presented

5 to this Commission some concern about testimony that had

6 been filed in addition to the previous prefiled testimony

7 for Ms. Carlock that may have some impact on your ability

8 to put forth your rebuttal case. Could you maybe bring us

9 up to where the Company is today with regards to its

10 rebuttal case so that we can move forward in at least

11 trying to plan out the remaining of the proceedings here?

12 MR. RIPLEY: Most certainly. The Company is

13 prepared to present witnesses Simard and Peseau as we go

14 forward now. As far as the witnesses of Carlock -- as far

15 as the witnesses of Hoyd and Gale are concerned, we had a

16 discussion during the noon hour and we are going to prepare

17 some additional testimony to address the issue raised by

18 Ms. Carlock. At this point I do not know if it's going to

19 be in Mr. Gale's testimony, Ms. Hoyd's testimony or both as

20 to any revisions that we would have to make to those two

21 witnesses, so we would request that probably the most

22 efficient way to do it is that we would proceed this

23 afternoon with Mr. Simard and Dr. Peseau and then we would

24 request that we be given overnight to prepare some

25 additional rebuttal and we would then present that

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CSB REPORTING COLLOQUY
Wilder, Idaho 83676

1 additional rebuttal hopefully in a Q/A format along with

2 the rebuttal testimony of Mr. Gale and Ms. Hoyd.

3 COMMISSIONER KJELLANDER: Thank you. All

4 right, then is the order that at least has been proposed

5 earlier with Mr. Simard and Mr. Peseau still the order in

6 which you would like to proceed?

7 MR. RIPLEY: Yes, sir.

8 COMMISSIONER KJELLANDER: Then please

9 proceed.

10 MR. RIPLEY: If I could have a couple of

11 minutes to change books.

12 COMMISSIONER KJELLANDER: It sounds fine.

13 (Pause in proceedings.)

14 MR. RIPLEY: I call Mr. Simard.

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CSB REPORTING COLLOQUY
Wilder, Idaho 83676

1 TIM J. SIMARD,

2 produced as a rebuttal witness at the instance of the Idaho

3 Power Company, having been previously duly sworn, resumed

4 the stand and was further examined and testified as

5 follows:

6

7 DIRECT EXAMINATION

8

9 BY MR. RIPLEY:

10 Q Mr. Simard, would you please state your name

11 for the record?

12 A Tim Simard.

13 Q And your business address?

14 A My business address is Suite 610, 1414 8th

15 Street S.W., Calgary, Alberta, Canada.

16 Q Mr. Simard, did you have cause to be prepared

17 for this proceeding certain prefiled testimony consisting

18 of 27 pages and did your testimony also identify

19 Exhibits 17, excuse me, yes, 17 through 24?

20 A Yes, sir.

21 Q And if I asked you the questions that were

22 set forth in your prefiled testimony, would your answers be

23 the same today?

24 A Yes, sir.

25 Q And are there any changes to your exhibits?

471

CSB REPORTING SIMARD (Di-Reb)
Wilder, Idaho 83676 Idaho Power Company

1 A No, sir.

2 MR. RIPLEY: I would ask that Mr. Simard's

3 prepared testimony be spread upon the record as if read and

4 his exhibits be marked as indicated in his prepared

5 testimony.

6 COMMISSIONER KJELLANDER: Without objection,

7 we will spread the testimony and admit the exhibits.

8 (Idaho Power Company Exhibit

9 Nos. 17 - 24 were admitted into evidence.)

10 (The following prefiled rebuttal

11 testimony of Mr. Tim Simard is spread upon the record.)

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472

CSB REPORTING SIMARD (Di-Reb)
Wilder, Idaho 83676 Idaho Power Company

1 Q. Please state your name and business address.

2 A. My name is Tim J. Simard. I am employed by

3 RiskAdvisory. My business address is Suite 610, 1414 8th

4 Street S.W., Calgary, Alberta, Canada T2R 1J6.

5 Q. What position do you hold with RiskAdvisory?

6 A. I am a founding Principal of RiskAdvisory.

7 Q. Please describe your experience relevant to

8 this testimony?

9 A. I began working with energy companies with

10 respect to the use of risk management instruments and the

11 design of risk management programs in 1986 as an

12 institutional energy futures broker with the Burns Fry

13 Energy Group in Calgary, Alberta. In 1990, I moved to

14 Bankers Trust Canada where I went on to become Vice Chairman

15 with responsibilities for managing Bankers Trust's Canadian

16 energy derivatives operation. RiskAdvisory was created in

17 1995 and since that time the firm has worked on assignments

18 for over 150 energy companies in the United States, Canada

19 and New Zealand. I have been involved in assignments with

20 16 electric and natural gas utilities as a member of

21 RiskAdvisory, primarily with respect to the design and

22 implementation of risk management programs. I have served

23 as an expert witness on issues pertaining to the financial

24 management of energy risk in four regulatory hearings for

25 both natural gas and electric utilities.

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SIMARD, DI-REB 1
Idaho Power Company

1 Q. Have you been retained by Idaho Power Company

2 ("IPC") or its parent IDACORP, Inc. In any other

3 assignments prior to your involvement as an expert witness

4 for these hearings?

5 A. Yes. I was engaged by IDACORP, Inc. In

6 September 2000 to work with the non-operations group as an

7 Interim Risk Manager. The assignment was to have terminated

8 on December 8, 2000. However, my services were retained on

9 a part-time basis beyond this period until March 1, 2001.

10 Q. As part of this assignment, what involvement

11 did you have with the utility risk management activity of

12 IPC?

13 A. My activity was limited to attendance at most

14 of the Risk Management Committee ("RMC") meetings held

15 during the term of my assignment. I listened to the

16 discussions around the risk management issues for the

17 operating function, but did not actively participate in

18 these discussions. My focus was on reporting to the Risk

19 Management Committee those issues pertaining to the risk

20 portfolio of the non-operating trading and marketing

21 activities.

22 Q. What is the purpose of your testimony?

23 A. The purpose of my testimony is twofold. The

24 first purpose is to provide contextual information on price

25 movements in regional spot and forward electricity markets

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SIMARD, DI-REB 2
Idaho Power Company

1 over the course of the 2000 - 2001 Power Cost Adjustment

2 ("PCA") Year and the potential impact of these movements on

3 the risk management activities of regional utilities. The

4 second purpose of my testimony is to discuss the transfer

5 pricing mechanism used to price utility transactions

6 between the operating and non-operating functions of IPC.

7 Q. What data and testimony have you reviewed in

8 the course of this case?

9 A. I have reviewed historical pricing and

10 volatility data for the Mid-C market through the period

11 April 2000 - February 2001. I have reviewed all the

12 testimony submitted for IPC-E-01-7 and IPC-E-01-11. I have

13 reviewed volume estimates provided by Dow Jones with respect

14 to the Mid-C indexing mechanism. I have reviewed forecast

15 and actual IPC resource and load statistics supplied by IPC

16 for the April 2000 - February 2001 period.

17 Q. What are forward prices?

18 A. A forward price is the price established in a

19 marketplace between buyers and sellers for a specific asset

20 or commodity for delivery on or during a specific timeframe

21 at a specific delivery point with a specified degree of

22 firmness or reliability. If buyers and sellers today agreed

23 to a price of $100 for firm November 2001 on-peak power

24 delivered at Mid-C, then $100 would be today's forward price

25 for electricity to be delivered throughout the month during

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SIMARD, DI-REB 3
Idaho Power Company

1 on-peak hours for the month of November at Mid-C.

2 Q. How are forward market prices set?

3 A. In an efficient forward marketplace, the

4 forward price represents the markets consensus expectation

5 of the future spot price. Assume that a detailed review

6 conducted today of all the fundamental factors that might

7 affect November Mid-C prices led market participants to

8 believe that the average on-peak spot price for Mid-C in

9 November will be $80. If the current forward price was $100,

10 market participants would quickly enter the market and

11 commit to sell the power at a fixed price of $100 for

12 November on-peak deliveries, with the expectation that they

13 would generate a $20 per MWh profit. This would be

14 accomplished by purchasing spot power during the month of

15 November at their expected November price of $80 to supply

16 the commit to deliver power at the fixed price of $100. In

17 a similar fashion, if the current November Mid-C on-peak

18 forward price was $60, then market participants would

19 quickly enter the market and commit to purchase power at a

20 fixed price of $60 for November on-peak deliveries. The

21 expectation again would be for a $20 profit with the belief

22 that these fixed price purchases of $60 could be sold back

23 into the spot market in November at the expected spot price

24 of $80. This buying and selling activity by participants

25 will continue until the equilibrium forward price equates to

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SIMARD, DI-REB 4
Idaho Power Company

1 the market consensus of future spot prices during the month

2 of November.

3 The ability to profit from buying or selling

4 in forward markets is predicated on the existence of some

5 form of competitive trading advantage and the willingness

6 to take risk. Competitive trading advantages are rare and

7 only the most skilled traders can consistently generate

8 profits by taking directional price views on forward

9 markets. Consistent profits earned from taking directional

10 price views in the past does not provide any guarantee that

11 consistent trading profits will be generated from taking

12 these price views in the future.

13 Q. Will the forward price for a given period

14 usually be lower than actual spot prices for that period?

15 A. No. In the testimony of Terri Carlock on

16 page 8 it is stated that "Term transactions reduce the price

17 variability and usually the cost for that time period." This

18 implies that the forward price for a given period is usually

19 lower than the actual spot prices for that period. If one

20 was a trader and knew this to be the case, one would always

21 buy power on the forward market and then wait to sell this

22 power into the higher-priced spot market at the time of

23 delivery. If the trading community in general was aware of

24 this relationship, all the traders would always be

25 purchasing power on the forward market. It should be clear

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SIMARD, DI-REB 5
Idaho Power Company

1 that at some point all this buying leads to very high

2 forward prices and that the likelihood of spot prices

3 falling below these high forward prices increases. To

4 reiterate, the forward price represents the market

5 consensus of future price movements there is no free lunch

6 and unfortunately no standard trading rule that can allow

7 one to make riskless trading profits by buying or selling

8 in the term market.

9 Q. What is meant by implied volatility?

10 A. Implied volatility is a term associated with

11 the valuation of put and call options. Options provide their

12 holders with the right but not the obligation to buy or sell

13 an underlying asset or commodity at an agreed-upon price at

14 some defined point in the future. Options are similar to

15 conventional insurance policies: the owner of a call option

16 has acquired insurance against higher prices, while the

17 owner of a put option has acquired insurance against lower

18 prices. In the same way that there is a component to the

19 pricing of conventional insurance that is tied to the

20 likelihood of occurrence of the even that is being insured,

21 there is a component of option pricing that gauges the

22 likelihood of a payout on the option contract. In financial

23 markets, the probability of a payout on the option is based

24 on the expected breadth of the distribution of possible

25 prices for the underlying asset or commodity at the maturity

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SIMARD, DI-REB 6
Idaho Power Company

1 date of the option. If the price distribution is expected to

2 be very narrow, the value of the price insurance falls and

3 the cost of the option will be lower. If the price

4 distribution is expected to be quite wide, the value of the

5 insurance rises and the cost of the option will increase.

6 If there are options trading on a particular

7 commodity, the price at which these options are valued

8 provides an indication of the market's assessment of the

9 anticipated future variability in the price of that

10 commodity. Option pricing models exist which allow one to

11 input the price of a specific option and the output will be

12 this indication of future price variability over the life

13 of the option, and it is this estimate of future price

14 variability which is termed implied volatility.

15 Q. How are implied volatility levels established

16 in the marketplace?

17 A. Implied volatility levels are established

18 based on the market's consensus view around the anticipated

19 future price variance of the underlying commodity. Assume a

20 November forward price is currently trading at $100. Also

21 assume that the nature of the current fundamental supply and

22 demand environment leads market participants to believe that

23 it is highly unlikely that actual spot prices in November

24 will trade outside of a band between $95 and $105. In this

25 environment, the cost of a $105 call option which would

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SIMARD, DI-REB 7
Idaho Power Company

1 ensure one against a price rise above $105 would not be very

2 valuable. Now assume that the market price of this $105 call

3 option is $100. Market participants who believe that there

4 is only a remote possibility of prices trading above $105

5 would sell this option and collect the insurance premium of

6 $100. Now assume that this $105 call option is trading at

7 $0.01. While the likelihood of prices trading above $105 may

8 be deemed to be low, the small probability of a price rise

9 above this level would justify market participants

10 purchasing this price insurance for $0.01. This buying and

11 selling of the option would continue until an equilibrium

12 price was attained that reflected the expected payout on

13 the option tied to the market's expectation of the magnitude

14 of the potential price distribution at maturity. This once

15 again is measured by the implied volatility of the option.

16 The implied volatility measure provides an

17 objective assessment of the market's expectation of

18 potential price dispersion in the future. If implied

19 volatility levels are high, this implies that there is a

20 substantial risk associated with maintaining market

21 exposure because the market anticipates material swings in

22 price. Low implied volatility would suggest there is less

23 risk associated with maintaining market exposure.

24 Q. Please describe the movement in forward

25 prices for the December 2000 - February 2001 timeframe over

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SIMARD, DI-REB 8
Idaho Power Company

1 the course of the 2000 - 2001 PCA year.

2 A. Exhibit 17 details the movement in the

3 average forward price for this three-month on-peak block

4 for Mid-C deliveries. The chart shows the clear upward

5 trend starting from $35 at the beginning of the PCA year

6 and escalating to $120 by the end of August. After a

7 two-month hiatus in the price escalation, the market for

8 this three-month forward period resumed its climb in

9 November, culminating in a spot average over the three

10 months for on-peak deliveries of $367.92.

11 Q. Please describe the movement in implied

12 volatility levels for the December 2000 - February 2001

13 timeframe over the course of the 2000 - 2001 PCA year.

14 A. Implied volatility levels associated with

15 this forward period rose steadily over the course of the

16 year as shown in Exhibit 18. There was a significant

17 increase in implied volatility in the July through September

18 period with the volatility rising from 26% to 67% over this

19 period. The implied volatility increased again in November

20 and continued on to higher levels in December and January.

21 Q. Is it reasonable to assume that IPC should

22 have had advance knowledge of the significant price

23 increase that occurred during the December 2000 - February

24 2001 timeframe?

25 A. No. Exhibit 19 incorporates both forward

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SIMARD, DI-REB 9
Idaho Power Company

1 price and implied volatility information to arrive at an

2 assessment of the market's consensus expectation of severe

3 price rises. The actual daily average unweighted Mid-C on-

4 peak index price for the December - February timeframe was

5 $367.92. Up until July 1, 2000, the market was assigning

6 only a 5% probability to the average December - February

7 price rising above $85. Even at the beginning of October,

8 the market was only assigning a 5% probability to prices

9 rising above $160. The movement above $350 was not

10 anticipated by the marketplace until it happened. It should

11 also be remembered that if the market had advance warning

12 that spot prices would average above $350 for this three-

13 month period, then the forward prices at which one would be

14 able to enter into term purchases would also be above $350.

15 There may be a perception that the clear

16 underlying upward trend in prices through 2000 would have

17 provided IPC with a signal that market prices would continue

18 to rise through the December - February timeframe. In the

19 testimony of Terri Carlock on page 30 it is stated "Price

20 trends from Idaho Power documents also reflect forward

21 prices for January 2001 increasing." If the trading rule

22 existed that rising markets in the past indicated rising

23 markets in the future, today the NASDAQ would be setting new

24 highs. No matter what has happened to forward market prices

25 in the past, there will always be approximately an equal

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SIMARD, DI-REB 10
Idaho Power Company

1 probability that the price will either fall or rise from

2 today's forward pricing level.

3 Q. If a trading company profits from a forward

4 market purchase in a particular month because market prices

5 subsequently rise after the purchase, can one state that

6 the trading company entered the position because it

7 believed prices were likely to rise?

8 A. No. Many trading companies profit from

9 arbitrage opportunities or spread transactions rather than

10 from the establishment of positions based on outright

11 directional market views. Arbitrage transactions represent

12 riskless or low-risk transactions. For example, if one can

13 purchase term power at a fixed price at Point A and arrange

14 firm transmission to move the power to Point B, and in turn

15 sell the power at Point B on a term basis at a fixed price

16 above the sum of the fixed purchase cost and the cost of

17 transmission, one has achieved a low risk arbitrage. In this

18 transaction, the fixed price term purchase at Point A is

19 made without regard for a directional price view. In fact,

20 even if the trading company was somewhat negative on future

21 price direction, the purchase at Point A would still likely

22 be made in order to capture a low risk arbitrage profit.

23 Trading companies also frequently take

24 positions on the direction of price spreads in the

25 marketplace. In many instances, the risk in a spread

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SIMARD, DI-REB 11
Idaho Power Company

1 position is less than the risk in an outright purchase or

2 sale, and the lower-risk nature of these transactions will

3 appeal to many trading groups. For example, a trading

4 company may believe that Mid-C prices are likely to rise

5 more or fall less than Palo Verde prices. If this is the

6 case, the trading company would purchase term power at Mid-C

7 and in turn sell term power at Palo Verde. The purchase at

8 Mid-C could be made even if the trading company believed

9 that the market price at Mid-C was likely to fall.

10 An example of the extent to which purchases

11 are often offset by sales is evidenced by the trading

12 practices of the non-operating trading group at IPC during

13 the recent PCA year. Exhibit 20 depicts the monthly term

14 purchases and sales entered into by the Idaho Power non-

15 operations trading group. A glance at the Purchases column

16 in isolation would suggest that the trading group had a

17 strong underlying price view all year long that prices would

18 rise. However, if one nets the term sales against these term

19 purchases, a much different story emerges. First, the

20 magnitude of the net position is only a fraction of the

21 outright purchases and sales (typically under 5%). More

22 importantly, the data reveals that in most months through

23 the year, the trading group actually entered into a greater

24 volume of sales than purchases.

25 Q. Should the opinion of a trading entity with

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Idaho Power Company

1 respect to the potential direction of market price

2 movements influence the implementation of forward market

3 risk management transactions for a regulated utility?

4 A. No. The risk management transactions

5 established by a utility on behalf of its ratepayers should

6 not incorporate price views. Given that the utility does

7 not have the ability to predict future prices, the

8 incorporation of price view into the hedging decision

9 injects an element of speculation that has no place in a

10 defensive risk management program.

11 Q. What were the risks faced by IPC if it had

12 established a forward long position in November 2000 in an

13 attempt to insulate ratepayers against higher power supply

14 costs?

15 A. There were several risks faced by IPC with

16 respect to the execution of a fixed price term purchase

17 during November 2000. First, there was a large degree of

18 uncertainty surrounding the actual surplus/deficit position

19 in any given month. If IPC had purchased power in the term

20 market to bring an expected deficit back into balance, an

21 increase in available generation could have put the utility

22 in a surplus position. If market prices had fallen (which

23 was just as probable as a market rise), losses would have

24 been incurred on a term purchase that as it turned out was

25 not necessary.

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SIMARD, DI-REB 13
Idaho Power Company

1 Second, by the time the risk of a substantial

2 price move was identified, market prices had already

3 escalated dramatically. Although the December - February

4 average forward price at the beginning of November was

5 $86.00, Exhibit 17 indicates that by mid-November the

6 average price for this three-month term purchase had

7 escalated to more than $150.00. Whether one looks at early

8 or late November, the price that could be fixed for this

9 period was a substantial multiple of the previous year's

10 price for this three-month period of $26.33. While the risk

11 of a further price rise was evident, it should be remembered

12 that a risk of a material price decline was also evident. If

13 a fixed price transaction had been established at $100,

14 substantial losses could have been incurred on this position

15 if prices had fallen. There was no assurance that the

16 regulator or intervenors would necessarily accept this high

17 price resource if market prices had collapsed. This

18 represents a common utility dilemma when regulators and

19 intervenors have not pre-approved a risk management

20 strategy. The problem rests with the fact that the utility

21 is acting on behalf of ratepayers and it is put in a

22 position where it must guess the risk appetite of the

23 ratepayers. Would ratepayers have wanted a $100 fixed price

24 term purchase in their portfolio that left no potential to

25 participate in a falling price environment? In hindsight it

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SIMARD, DI-REB 14
Idaho Power Company

1 is easy to respond in the affirmative. However, at the time

2 in the midst of a substantial escalation in price that left

3 forward markets well above year-earlier levels, it is not

4 so clear that ratepayers would have been desirous of a

5 forward market hedge at such a high price. Without

6 pre-approval of a hedging strategy, the utility is left in

7 the untenable position where after the fact, in a rising

8 price environment the regulator and intervenor can assert

9 that a hedge was desired, while in a falling price scenario

10 the claim could be made that no hedge was desired.

11 Q. Please comment on the magnitude of spot

12 market purchases in the IPC resource portfolio for January

13 and February 2001.

14 A. The testimony of Terri Carlock suggests a

15 concern surrounding the magnitude of day-ahead and real-time

16 purchases in the IPC portfolio as opposed to term purchases.

17 The concern is supported by Exhibit 109 which indicates that

18 over 90% of system purchases for these two months were on

19 the spot market while less than 10% of the portfolio was

20 supplied through term purchases. It is important to

21 recognize that the resources used to serve system load

22 requirements extend well beyond wholesale market purchases.

23 Exhibit 21 provides a depiction of the breakdown of the

24 actual IPC resource portfolio for the past PCA year. For

25 the months of January and February, spot market purchases

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SIMARD, DI-REB 15
Idaho Power Company

1 represented only 15% and 13% of the total resource

2 portfolio. The added complexity of factoring in the

3 uncertainty around hydro availability is evident in

4 Exhibit 22. Based on the Idaho Resource Plan, the months of

5 January and February were expected to be in surplus, so that

6 no spot purchases would have been required. Based on the

7 plan at the start of the year, one might ask why term sales

8 were not established to protect the value inherent in the

9 surplus for the months of January and February. Of course

10 this would have led to even greater spot purchase

11 requirements for these months given the contraction in

12 available generation resources versus the plan. This

13 highlights the difficulty inherent in entering into risk

14 management transactions with such uncertainty around hydro

15 output: term transactions that are established with the aim

16 of reducing risk can sometimes lead to higher risk

17 scenarios. Any analysis of IPC risk management activity

18 must recognize the fact that senior management will not

19 have perfect information about its future surplus/deficit

20 position.

21 Q. There is a perception that when energy was

22 transferred from the non-operating book to the operating

23 book at the specified market prices, and these market prices

24 were systematically higher than the actual non-operating

25 energy purchase prices, the utility purchased energy for the

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SIMARD, DI-REB 16
Idaho Power Company

1 system at a price higher than it should have paid. What is

2 your response to this criticism?

3 A. There are several responses to this

4 perception. First, as has been discussed earlier, many of

5 the low-cost term purchases made by the non-operating book

6 were offset by term sales. Power may have been purchased at

7 a low fixed price at Point A and then sold at a marginally

8 higher price at Point B. Both the term fixed purchase and

9 sale prices could easily be well below actual spot prices

10 through time.

11 Second, many of the purchases in the non-

12 operating book were made at delivery points other than the

13 IPC border and substantial transmission costs in many

14 instances would have to be incurred to move this power if

15 it was to serve native load.

16 Third, if the non-operating book was taking a

17 long speculative position, IDACORP shareholders were

18 exposed to the market risk in these positions. If power was

19 purchased on the term market at a fixed price of $100 and

20 then sold into a depressed spot market at $30, the

21 shareholders would absorb a $70 loss. The non-operating

22 book had no capacity to pass along high-priced purchases to

23 the system.

24 Fourth, as has already been discussed, if the

25 non-operating book did capitalize from time to time on a

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SIMARD, DI-REB 17
Idaho Power Company

1 speculative belief that market prices would rise, this does

2 not mean that this speculative market view should have

3 influenced system risk management transactions. Although

4 the non-operating book may have perceived that prices would

5 rise, it did not know that prices would rise. Prices could

6 just as easily have faltered. The decision to buy or sell

7 on the term market for the system should not be a function

8 of a price view.

9 Q. What is your understanding of the day-ahead

10 transfer pricing mechanism that has been used to price

11 transactions between the operating and non-operating

12 business units within IPC?

13 A. It is my understanding that the transfer

14 price between the operating and non-operating books for day

15 ahead transactions is the Firm Daily Index for Mid-Columbia

16 ("Mid-C") power transactions as published by Dow Jones,

17 adjusted for the cost of transmission to move the power

18 between Mid-C and the Idaho border. For sales made by the

19 system to the non-operating book, transmission costs are

20 subtracted from the index, and these costs are added for

21 purchases made by the system from the non-operating book.

22 Transmission costs are determined by taking the average firm

23 transmission tariffs plus transmission losses of all

24 transmission providers between Mid-C and the Idaho border.

25 While the Services Agreement between IPC and IDACORP Energy

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SIMARD, DI-REB 18
Idaho Power Company

1 Solutions LP calls for the alternative use of a Palo Verde

2 index, in practice the Mid-C transfer pricing mechanism was

3 used exclusively through February 2001.

4 Q. Is the use of an index price commonly used as

5 a transfer pricing mechanism in the energy sector?

6 A. Yes, it is conventional practice in the

7 energy sector for transactions between buyers and sellers

8 to be tied to an index price. These indices take the form

9 of either price surveys of market participants reported in

10 industry publications like the Dow Jones Mid-C index, or

11 the pricing from a commodity exchange like the New York

12 Mercantile Exchange ("NYMEX").

13 Q. What are the benefits associated with the use

14 of an index transfer pricing mechanism?

15 A. An index transfer mechanism allows one to

16 enter into a term marketing/supply arrangement at a price

17 which on an ongoing basis is representative of the price at

18 which spot transactions are being conducted through time.

19 In addition, in more mature markets, the index pricing

20 mechanism allows one to enter into financial derivative

21 transactions to manage the volatility risk inherent in the

22 price index separate and apart from the underlying physical

23 transaction.

24 Q. What concerns should one have with the index

25 used in the transfer pricing mechanism?

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SIMARD, DI-REB 19
Idaho Power Company

1 A. The index price should be transparent,

2 meaning that market participants are able to track

3 transactions at that point through time. The index price

4 should be for a liquid point where many transactions are

5 concluded on a daily basis. The index price should be free

6 from manipulation by the parties using the index for a

7 transfer price. The index price chosen for a transfer price

8 between two entities should also be representative of

9 pricing for transactions similar to those contemplated

10 under the commercial transfer.

11 Q. Is the Mid-C index transparent?

12 A. Yes. The most transparent indices are those

13 tied to market exchanges like the NYMEX or electronic

14 exchange mechanisms. Transactions occur throughout the day

15 and prices and transaction prices are transmitted

16 immediately to market participants. While the Dow Jones Mid-

17 C index itself is not an exchange-based mechanism, the day-

18 ahead Mid-C market price is actively quoted by a number of

19 electronic exchanges. With the survey approach taken by Dow

20 Jones of significant market participants in the

21 marketplace, transactions that occur through the electronic

22 exchanges should make their way into the Dow Jones index

23 calculation. This provides an element of transparency to

24 this particular Mid-C index pricing mechanism.

25 Q. Is the Mid-C index point liquid?

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SIMARD, DI-REB 20
Idaho Power Company

1 A. Yes. It is estimated that approximately 2000

2 MW trades daily in the Mid-C day-ahead marketplace. In

3 addition, the ability to move power into and out of Mid-C

4 on a range of transmission paths causes the Mid-C price to

5 be affected by market developments throughout the Pacific

6 Northwest region. During the calendar year 2000, data from

7 Dow Jones indicates that the average daily on-peak

8 day-ahead volume recorded through their survey was 1430 MW,

9 representing more than 70% of the estimated average daily

10 volume transacted at Mid-C. Exhibit 23 provides a list of

11 the 40 key market participants who are surveyed by Dow

12 Jones as part of the index determination process. This

13 documents that the pricing information is based on the

14 transactional data of a broad industry group.

15 Q. Was the Mid-C index subject to manipulation

16 by the non-operating trading function of IPC?

17 A. Most indices based on industry surveys of

18 transactions are subject to potential manipulation. One can

19 report non-factual pricing to the surveyor in an effort to

20 distort the actual price. However, the index publications

21 recognize that the representative nature of the index is

22 crucial to the survival of the index as an industry pricing

23 benchmark. As a result, steps are taken to ensure the

24 accuracy of the submitted transaction prices. Dow Jones

25 attempts to match the price on reported purchases with the

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SIMARD, DI-REB 21
Idaho Power Company

1 price on reported sales and if there is a mismatch the

2 parties are contacted to correct the possible error. In

3 addition, Dow Jones retains the right to audit those groups

4 who are submitting prices and it has exercised its right to

5 audit in the past. These factors limit any group's ability

6 to manipulate the index.

7 It is possible that the non-operating book

8 generated profits from the day-ahead activity conducted for

9 the system, but this would not have been generated in a

10 risk-free fashion, and ratepayers would not have been

11 harmed by this action.

12 If one examines the day-ahead system

13 purchases and sales by the system during the April 2000 -

14 February 2001 timeframe, the average volumes do appear to

15 be material versus the estimated volumes trading at Mid-C.

16 However, this is mitigated to a large extent by the fact

17 that most of the purchases and sales done by the non-

18 operating book to meet its day-ahead purchase and sales

19 obligations to the system were not effected through the Mid-

20 C delivery point. Exhibit 24 highlights this point. Looking

21 at July as an example, the system purchased 342,356 MWh from

22 the non-operating trading group and the non-operating group

23 purchased only 102,408 MWh at Mid-C, representing less than

24 30% of the total purchased by the system. The balance of the

25 purchases would have been transferred in from other delivery

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SIMARD, DI-REB 22
Idaho Power Company

1 points or acquired at the IPC border. This serves to lessen

2 materially the influence that the system volumes might have

3 on the Mid-C index itself.

4 There is a concern that the information

5 imparted to the non-operating book with respect to the day-

6 ahead requirements of the system could lead to

7 "frontrunning" activity. Frontrunning occurs when a market

8 participant establishes a position for its own account prior

9 to executing transactions on behalf of a third party. The

10 proprietary position is established with the expectation

11 that the required market activity of the third party will

12 cause prices to move in favour of the position. The ability

13 to generate profits from this type of activity is a function

14 of the magnitude of transactions that must be executed by

15 the third party relative to the size of the entire market.

16 While the effect of the system volumes with respect to

17 moving the Mid-C market is mitigated by the use of power

18 sourced from other points than Mid-C, there is still a

19 possibility that the non-operating book could enter into

20 these types of transactions when it possesses information

21 about material day-ahead requirements for the system.

22 However, this should not be a concern to ratepayers. First,

23 if the non-operating book does enter into a purchase or sale

24 based on its assessment of the impact of system-related

25 volumes on the market, there will be no effect on the index

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SIMARD, DI-REB 23
Idaho Power Company

1 price used in the transfer pricing mechanism. Although the

2 non-operating book may initially purchase a day-ahead block

3 creating upward pressure on the index, it must also sell

4 this block later, creating downward pressure on the index.

5 The net effect will over time be neutral on the index.

6 Second, the buying or selling by the non-operating entity is

7 not risk-free. Assume that the non-operating book purchases

8 power with the expectation that prices will rise based on

9 system needs. Shortly after the purchase is consummated, a

10 large unit in the Northwest which was expected to be

11 offline comes back onstream. Day-ahead prices collapse,

12 even taking into account the system purchasing activity.

13 The speculative long position incurs a loss.

14 Q. Is the Mid-C index mechanism representative

15 of pricing for the commercial transactions between the

16 operating and non-operating business units

17 A. Yes. While the purchases and sales that are

18 transacted by the non-operating business incorporate many

19 more delivery points than Mid-C, this index is viewed in the

20 marketplace as the representative pricing index for the

21 Northwest. Exhibit 23 showed the extent to which regional

22 utilities and marketing companies are participating in the

23 Mid-C index price survey. There may be times when the actual

24 price of power sourced or sold in the day-ahead market

25 including transmission costs lies above the Mid-C price and

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SIMARD, DI-REB 24
Idaho Power Company

1 other times when the actual price is lower than the Mid-C

2 index price. However, the Mid-C index price continues to be

3 the best index proxy for IPC's regional market.

4 Q. Does the non-operating trading function face

5 any risks associated with the day-ahead index-based

6 transfer pricing mechanism?

7 A. Yes. There is no guarantee that the non-

8 operating group will be able to match or outperform the day-

9 ahead index price with respect to actual prices achieved in

10 the market. Assume that 100 MW must be purchased for system

11 requirements. The non-operating book buys this power at Mid-

12 C at a price of $100. Subsequent to this purchase activity

13 market prices fall to $80 and the majority of the day's

14 transactions are consummated at this lower level. The net

15 result is that the index is set at $85. The purchase at

16 $100 is offset with a sale to the system at the index price

17 of $85. The non-operating book suffers a $15 loss because of

18 its inability to match the index price. This risk is

19 compounded by the fact that the index represents a mid-

20 market price. When purchases must be made for the system,

21 one must access the offer side of the market which is higher

22 than the mid-market price, and sales must access the bid

23 side of the market which is lower than the mid-market

24 price. From this perspective, the index mechanism is skewed

25 marginally against the non-operating group.

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SIMARD, DI-REB 25
Idaho Power Company

1 In addition to the market execution risk, the

2 non-operating group also faces a transmission risk. The

3 transmission adjustment is based on the average tariff of

4 transmission providers. If the only transmission available

5 is at a tariff greater than this average, the non-operating

6 group will suffer a loss equal to the difference between

7 the actual tariff paid and the average tariff calculation.

8 Q. Do you believe the day-ahead index-based

9 transfer pricing mechanism is fair?

10 A. Based on the range of issues discussed above,

11 the Mid-C index with the transmission component represents

12 a fair transfer pricing mechanism.

13 Q. What is your understanding of the real-time

14 transfer pricing method used to price transactions between

15 the operating and non-operating business units within IPC?

16 A. From December 2000 through February 2001,

17 real-time transactions during a particular hour were priced

18 on the basis of the weighted average delivered price of all

19 transactions entered into by the non-operating book at the

20 IPC border for that hour.

21 Q. Are there differences in the effectiveness of

22 the real-time transfer pricing mechanism vis-…-vis the

23 day-ahead transfer pricing mechanism?

24 A. Yes. There is no price transparency for the

25 real-time pricing mechanism. There will be limited liquidity

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SIMARD, DI-REB 26
Idaho Power Company

1 from time-to-time with respect to these transactions.

2 However, the index is completely representative of the

3 price at which a passive marketing/supply group would

4 manage the real/time surplus/deficit position.

5 Q. Do you consider the real-time transfer

6 pricing mechanism to be an appropriate method to price the

7 real-time transactions between IPC's operating and

8 non-operating business units?

9 A. Yes.

10 Q. Does this conclude your testimony.

11 A. Yes.

12

13

14

15

16

17

18

19

20

21

22

23

24

25

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SIMARD, DI-REB 27
Idaho Power Company

1 (The following proceedings were had in

2 open hearing.)

3 MR. RIPLEY: We would tender Mr. Simard for

4 cross-examination.

5 COMMISSIONER KJELLANDER: Okay, let's move

6 now to the Deputy Attorney General representing the PUC

7 Staff.

8 MS. NORDSTROM: Thank you.

9

10 CROSS-EXAMINATION

11

12 BY MS. NORDSTROM:

13 Q Good afternoon.

14 A Good afternoon.

15 Q Directing your attention to page 12 of your

16 testimony, in lines 4 through 6 you state that the risk

17 management transactions established by a utility on behalf

18 of its ratepayers should not incorporate price views; isn't

19 it true?

20 MR. RIPLEY: Excuse me, do you have the right

21 page, Counsel?

22 MS. NORDSTROM: I'm sorry, I thought it was

23 page 12.

24 MR. RIPLEY: This is Mr. Simard?

25 MS. NORDSTROM: Yeah.

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CSB REPORTING SIMARD (X-Reb)
Wilder, Idaho 83676 Idaho Power Company

1 Q BY MS. NORDSTROM: Well, even if it isn't

2 page 12, that's the tenor of your testimony; is that

3 correct?

4 A I'm sorry, could you repeat the question?

5 Q Even if it's not on page 12, not

6 incorporating a price view into risk management decisions

7 is a tenet of your testimony; is that correct?

8 A For utilities, yes, that's correct.

9 Q Isn't it true that Idaho Power incorporated a

10 price view by considering historical prices when it decided

11 not to purchase a hedge for January 2001?

12 A I'm not exactly sure of what was going

13 through the minds of the Idaho Power Risk Management

14 Committee when it was thinking of hedge positions, but in

15 subsequent conversations, I think one of the things that

16 concerned them was that the application of a hedge position

17 would have been done in an environment where they did not

18 have certainty around the risk appetite of their

19 ratepayers, so, for example, if the opportunity presented

20 itself to establish a forward hedge position at $150 a

21 megawatt-hour, there would have been a question in the

22 minds of Idaho Power as to whether ratepayers really wanted

23 a hedge at $150, because as soon as that hedge position is

24 established, the ratepayer would forfeit any participation

25 in a falling price environment and so if prices had

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CSB REPORTING SIMARD (X-Reb)
Wilder, Idaho 83676 Idaho Power Company

1 subsequently fallen to $25.00 a megawatt-hour, the

2 ratepayers would have been left in a position where they

3 were paying $150 a megawatt-hour for that energy and in

4 hindsight, there could have been some criticism potentially

5 directed at Idaho Power for establishing that kind of hedge

6 position.

7 Q And that's why you're advising them not to

8 incorporate price views; is that correct?

9 A My advice from the start has been with the

10 recent mandate assisting Idaho Power Company going forward

11 is that as much as possible it needs to reach a consensus

12 with ratepayer groups and Staff surrounding what is deemed

13 to be the appropriate strategy for managing the risk of the

14 ratepayer.

15 Q But back to my original question, was

16 considering historical prices in essence taking a price

17 view?

18 A If historical prices were considered in the

19 decision, that is using a price view as part of the

20 decision making process.

21 Q On page 2, line 15 of your testimony, you

22 indicated that you attended most Risk Management Committee

23 meetings. In your memory, was there any discussion of the

24 decision to enter into a long-term hedge of real-time

25 versus day-ahead prices?

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CSB REPORTING SIMARD (X-Reb)
Wilder, Idaho 83676 Idaho Power Company

1 A No, there was not.

2 Q Back to page 13, you discussed several risks

3 faced by Idaho Power Company in November 2000. Wasn't one

4 significant risk factor whether or not the Company's

5 hydropower generation would meet normal forecast

6 projections?

7 A There was a risk as to whether it would meet

8 normal forecast projections, whether it would exceed normal

9 forecast projections or fall below normal forecast

10 projections.

11 Q If the Company estimates that its hydropower

12 generation will be less than normal, doesn't it have to

13 acquire additional power or reduce its load?

14 A Yes, but that can be done against a myriad

15 number of pricing mechanisms. It does not necessarily

16 imply that a fixed price purchase needs to be established

17 to cover that shortfall.

18 Q How would the Company normally acquire that

19 additional power?

20 A It could acquire additional power through a

21 wholesale forward transaction. It could acquire power on a

22 day-ahead basis or it could acquire power on a real-time

23 basis.

24 Q But for the last half of the PCA period,

25 isn't it true that the Company relied primarily on

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CSB REPORTING SIMARD (X-Reb)
Wilder, Idaho 83676 Idaho Power Company

1 day-ahead short-term markets to buy that additional power?

2 A Most of the power source to supply native

3 load came from the system's own resources. The resulting

4 until December unexpected shortfall in resources relative

5 to the native load position ended up being supplied

6 primarily by day-ahead and real-time purchases as opposed

7 to entering into forward transactions at very, very high

8 prices.

9 Q During the 2000-2001 PCA year, Idaho Power

10 Company was the counterparty for all hedging and

11 speculative trades. To assist in determining the credit

12 risk exposure of Idaho Power Company during that time,

13 could you generally discuss what types of speculative

14 trading the non-operating group was engaging in?

15 A I have a reasonable idea of the nature of

16 many of the transactions that the non-op trading group was

17 engaged in and many of those transactions were arbitrage

18 transactions tied to non-territorial transmission positions

19 that had been acquired.

20 Q Do you have a general sense of the cost of

21 credit intermediation services in the energy market?

22 A I have a general sense, but it's difficult

23 for me to apply a standardized rule to the credit support

24 practices in the industry.

25 Q Could you just generally describe the range

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CSB REPORTING SIMARD (X-Reb)
Wilder, Idaho 83676 Idaho Power Company

1 of these costs in the open market?

2 A They range from nil to probably two to three

3 percent as a rough estimate.

4 Q Do you believe that the non-operating

5 system's speculative view of the market and the potential

6 risks and rewards of forward market in prices should be

7 reflected in Idaho Power Company's hedging positions?

8 A No, I do not.

9 Q The Staff's understanding is that one

10 potential benefit of the Idaho Power/IDACORP Energy

11 relationship was the retention of this type of market

12 knowledge. As the non-operating system or IDACORP Energy's

13 speculative position would imply, why shouldn't Idaho Power

14 Company have the advantage of such knowledge?

15 A I would have thought that one of the reasons

16 that the separation between the Idaho Power non-op group

17 and the operating group was created in the first place was

18 to ensure that the Idaho Power Company ratepayers were not

19 exposed to risk positions in the marketplace. When Idaho

20 Power, when non-op Idaho Power, engages in forward

21 transactions, there is never any certainty around those

22 speculative positions as to whether they are going to make

23 money or not and I think it would be entirely inappropriate

24 if a risk position was identified at the Idaho Power

25 Company level that was viewed as being an intolerable risk

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CSB REPORTING SIMARD (X-Reb)
Wilder, Idaho 83676 Idaho Power Company

1 to be taking on the part of the ratepayers.

2 If a decision to hedge was postponed because

3 of a price view emanating from the non-op group, for

4 example, if Idaho Power is significantly long resources in

5 a surplus position in one month and with that long position

6 is subsequently exposed to a fall in prices, it may be

7 deemed appropriate assuming certain risk tolerances

8 expressed by the ratepayers to go out and hedge that

9 transaction and they would hedge that transaction by

10 selling that power forward at a fixed price.

11 On the same day, it might be possible that

12 the non-op trading group believes prices will rise, doesn't

13 know prices will rise, but believes prices will rise and I

14 don't think it is appropriate for the ratepayers who are

15 desirous of a low risk position to have that potential

16 hedge shelved because of the price view emanating from a

17 trading and entrepreneurial marketing operation.

18 Q Since you believe that Idaho Power Company

19 should reject using a price view, how should Idaho Power

20 Company take market price risk and range of potential

21 market prices into effect in setting hedging strategies?

22 A They should be governed largely or entirely

23 on the risk tolerances expressed by Staff and ratepayers

24 and if one reaches a position where the amount of risk in

25 the Idaho Power Company position exceeds that risk

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CSB REPORTING SIMARD (X-Reb)
Wilder, Idaho 83676 Idaho Power Company

1 tolerance, then regardless of price levels, a hedge would

2 be implemented to bring the risk back within the

3 appropriate risk tolerance.

4 Q Since IE trades in the market more frequently

5 and with greater expertise, don't they have a more informed

6 impression of potential future risks and rewards of market

7 price movements than Idaho Power does?

8 A Idaho Energy may have more expertise with

9 respect to attempting to forecast prices. They're an

10 organization that has been set up to take risks and given a

11 certain amount of risk capital available to them, they will

12 attempt to maximize the profits they can generate from the

13 risk positions they take, but the key is that those

14 positions entail risk and the trading performance of

15 trading and marketing entities can be extremely volatile

16 and that is typically not the kind of exposure that a

17 utility ratepayer would want in his portfolio.

18 Q Well, that's not to say that Idaho Power

19 Company has to blindly do or rely on whatever impressions

20 IDACORP Energy has, but shouldn't they have the benefit of

21 those impressions?

22 A Once again, I think not because if the non-op

23 trading company thinks the price is going up, I can tell

24 you that there's another informed player in the marketplace

25 who thinks the price is going down. If all the informed

507

CSB REPORTING SIMARD (X-Reb)
Wilder, Idaho 83676 Idaho Power Company

1 players in the marketplace thought the price was going up,

2 the price would already be up, so for example, if everybody

3 thought the price was going to be $100 a megawatt-hour in a

4 given month and the forward price today is trading at

5 $80.00, then it's not going to take very long before that

6 forward price is trading at $100 and once we get to that

7 equilibrium level of $100 it's because many in the market

8 believe the price is going to go up and many in the market

9 believe the price is going to go down.

10 Q You've identified Idaho Power Company's

11 acknowledgment of risk tolerance. What actions did Idaho

12 Power Company take to determine Staff or customer risk

13 tolerance?

14 A Idaho Power is in the process, I believe as

15 we speak as part of the 16 case, is in the process of

16 developing that consultative and collaborative process to

17 attempting to identify the appropriate level of risk

18 tolerance. I would also ask what direction has been given

19 by ratepayers or the Staff or the board in the past with

20 respect to their risk tolerance?

21 Q I'm afraid I'm not sworn. I can't answer

22 that.

23 A That's fair.

24 Q If Idaho Power Company hasn't done it thus

25 far, to your knowledge, do you know why they haven't?

508

CSB REPORTING SIMARD (X-Reb)
Wilder, Idaho 83676 Idaho Power Company

1 A I think the main reason is that this whole

2 area of establishing a collaborative approach with

3 ratepayers around the appropriate risk management activity

4 is still very much in its embryonic stage throughout North

5 America.

6 Q Does the Idaho Power/IDACORP Energy service

7 agreement allow the IE model to minimize the outright price

8 speculation and to instead take advantage of superior

9 market knowledge of energy movement constraints?

10 MR. RIPLEY: Mr. Chairman, I'm going to

11 object simply because we are going outside the bounds of

12 the 7/11 case and now encroaching on the bounds of the 16

13 case. Mr. Simard is going to testify in the 16 case and

14 what agreements are or are not in place for IES is more

15 properly in the 16 case. There was no agreement, I believe

16 this record clearly demonstrates, up to at least

17 February 28, 2001 as far as its application to the PCA in

18 this proceeding except for real-time pricing.

19 MS. NORDSTROM: Staff will withdraw its

20 question.

21 COMMISSIONER KJELLANDER: Thank you.

22 MS. NORDSTROM: May I have just a moment?

23 COMMISSIONER KJELLANDER: Certainly.

24 (Pause in proceedings.)

25 Q BY MS. NORDSTROM: The Idaho Power position

509

CSB REPORTING SIMARD (X-Reb)
Wilder, Idaho 83676 Idaho Power Company

1 is that the Mid-C is a liquid, transparent trading

2 location; correct?

3 A Yes.

4 Q Would this imply that the implicit and

5 explicit transaction costs are the lowest at this point for

6 Idaho Power Company?

7 A I'm not sure I understand the question.

8 Q Is this the best place for them to trade?

9 A I believe that the Mid-C index is the best

10 regional index available. If one had a passive marketing

11 and supply operation at Idaho Power Company, then a

12 standard transaction that they would be entering into each

13 day would be the purchase or sale of power at Mid-C with

14 the appropriate transmission to and from the Idaho Power

15 border and as such, Mid-C is a very representative index of

16 the type of day-ahead activity that a passive marketing and

17 supply function would be active in.

18 Q Is there any other identifiable liquid and

19 transparent trading location available for IDACORP Energy

20 and Idaho Power Company?

21 A The only other one I can think of is

22 potentially the Palo Verde index which is not as

23 representative of most IPC transactions in the normal

24 course. That becomes a more representative index when

25 there are transmission constraints between Mid-C and the

510

CSB REPORTING SIMARD (X-Reb)
Wilder, Idaho 83676 Idaho Power Company

1 Idaho Power border, but absent those transmission

2 constraints between Mid-C and the Idaho Power border, I

3 believe that the Mid-C index is by far and away the most

4 representative index price that can be used to price these

5 transactions.

6 Q So does that mean to say that transmission

7 constraints may increase the risk of transacting at Mid-C?

8 A Transmission constraints increase the risk to

9 the non-operating trading entity of supplying power to

10 Idaho Power, the op side, at the transfer pricing

11 mechanism.

12 MS. NORDSTROM: No further questions. Thank

13 you.

14 COMMISSIONER KJELLANDER: We move now to

15 Mr. Richardson.

16 MR. RICHARDSON: No questions, Mr. Chairman.

17 COMMISSIONER KJELLANDER: Are there questions

18 from the Commission?

19 Commissioner Hansen.

20

21 EXAMINATION

22

23 BY COMMISSIONER HANSEN:

24 Q I guess I'd like you to kind of clarify for

25 me, on page 15, lines 5 through 10 of your rebuttal, are

511

CSB REPORTING SIMARD (Com-Reb)
Wilder, Idaho 83676 Idaho Power Company

1 you saying that Idaho Power Company did no hedging because

2 they had no preapproval?

3 A I would suggest that if they had preapproval,

4 preapproval within clear guidelines, they probably would

5 have entered into hedge transactions if that had been

6 dictated by the kind of preapproval that had been given.

7 Absent the preapproval, there was a substantial amount of

8 risk whether a transaction was put in place or not and I

9 keep coming back to the fact that if a hedge had been

10 established for, for example, the December-February period

11 at 150 to $200 a megawatt-hour and prices had suddenly

12 collapsed, there could easily have been some questioning on

13 the part of Staff and ratepayers on a hindsight basis as to

14 why anybody would have hedged at such a high price relative

15 to where we've been in the past knowing as we do now that

16 prices were set to collapse and, of course, that's the kind

17 of discussion that many California ratepayers may find

18 themselves in today.

19 Q So are you saying that Idaho Power wouldn't

20 do anything without the ratepayer's preapproval, that they

21 wouldn't do any hedging, shouldn't do any hedging without

22 having the ratepayer's preapproval of what they should do;

23 is that what you're saying?

24 A I think to their credit the historical

25 transaction record shows that in the past Idaho Power has

512

CSB REPORTING SIMARD (Com-Reb)
Wilder, Idaho 83676 Idaho Power Company

1 entered into transactions on behalf of its ratepayers, but

2 when it did that, it was taking on risk because there was

3 always the chance that those transactions in hindsight

4 would have been disallowed, and from my perspective, that

5 creates an inequity in the decision making process for IPC

6 and I much favor an approach where the individuals who are

7 truly affected here, the ratepayers, have input into the

8 process so that IPC has a better idea of exactly what the

9 risk appetite is of those ratepayers and to reduce the

10 likelihood of negative hindsight reviews.

11 Q Well, I guess the question I'd have is how

12 Idaho Power Company would get a consensus from the

13 ratepayers on the amount of risk and hedging they should

14 take when we as a Commission, we can't even under all of

15 all God's blue skies get a consensus from the ratepayers on

16 any particular issue. I mean, they're all over the board.

17 I mean, you've got some that would be willing to pay more

18 for, say, green power or whatever and some want the prices

19 even reduced a lot further. I guess, how do you propose

20 that they would get guidance from the ratepayer in order to

21 establish this?

22 A Well, I'd first like to comment that absent

23 that consensus, Idaho Power is being forced into that

24 position of attempting to identify the risk appetite of the

25 ratepayers with all the kinds of difficulties you indicate

513

CSB REPORTING SIMARD (Com-Reb)
Wilder, Idaho 83676 Idaho Power Company

1 and one thing is for certain, no matter what course they

2 take on a risk management front, they're not going to end

3 up with the lowest possible price and there's always a

4 chance that the ratepayers who have not been forced to

5 identify up front what their risk appetite is can come

6 along after the fact and say no, I'm sorry, you guessed

7 wrong. Any prudent person in that kind of environment

8 would not have established a hedge or would have

9 established a hedge at that point depending on how prices

10 subsequently moved, so I absolutely agree that the

11 mechanisms and process to attempt to identify what that

12 consensus view is, that's not an easy process and I believe

13 the most appropriate way to go forward is to look at who

14 are the representatives of the ratepayers. The intervenors

15 and the Staff, I would think, act as representatives of the

16 ratepayers and if they can be brought into the process,

17 they're the ones who presumably are in a much better

18 position to establish what the potential risk appetite of

19 those ratepayers might be.

20 COMMISSIONER KJELLANDER: Commissioner Smith.

21 COMMISSIONER SMITH: Yes, thank you.

22

23

24

25

514

CSB REPORTING SIMARD (Com-Reb)
Wilder, Idaho 83676 Idaho Power Company

1 EXAMINATION

2

3 BY COMMISSIONER SMITH:

4 Q I just wanted to follow up on something you

5 said in response to Commissioner Hansen's question and it

6 seems to me that what you don't like is the regulatory

7 process when you talk about this after the fact reviews,

8 because in my experience, that's essentially what happens

9 to a regulated entity is that there are after the fact

10 reviews and that's commonplace.

11 A Yes, my problem in this environment is that

12 often the decisions about prudency are made in hindsight

13 after market movements have already occurred and it is very

14 difficult to go back to the situation where the decision is

15 actually made and think about what the position the Company

16 is in at that time. In hindsight, it is very easy for a

17 ratepayer group to come forward and suggest that, you know,

18 the last thing in the world I wanted was a hedge at $150

19 for the winter because, you know, prices were obviously

20 peaking and here we are back down at 40.

21 Q And I agree and I think that is a tremendous

22 challenge for the Commission to remember that we're looking

23 at it from the position of what was known at the time and

24 not what we know now months later, but by the same token, I

25 think that that also puts a burden and a responsibility on

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CSB REPORTING SIMARD (Com-Reb)
Wilder, Idaho 83676 Idaho Power Company

1 the regulated entity and behooves them to keep the best

2 records possible so that the regulator can go back to that

3 point in time and say okay, what were you thinking.

4 A Recordkeeping is important. I also think

5 it's the responsibility of the utility to share as much

6 information as they can possibly share with ratepayer

7 groups and the board about what the nature and risks are in

8 the position.

9 Q And when you say the "board," you mean us,

10 you mean the Commission?

11 A The Commission, yes.

12 COMMISSIONER SMITH: Thank you. That's all.

13 COMMISSIONER KJELLANDER: Thank you. We move

14 now to redirect.

15 MR. RIPLEY: I have no redirect.

16 COMMISSIONER KJELLANDER: Okay, thank you,

17 sir.

18 THE WITNESS: Thank you.

19 (The witness left the stand.)

20 COMMISSIONER KJELLANDER: Would you like to

21 call your next witness?

22 MR. RIPLEY: I call Dr. Peseau.

23

24

25

516

CSB REPORTING SIMARD (Com-Reb)
Wilder, Idaho 83676 Idaho Power Company

1 DENNIS E. PESEAU,

2 produced as a rebuttal witness at the instance of the Idaho

3 Power Company, having been first duly sworn, was examined

4 and testified as follows:

5

6 DIRECT EXAMINATION

7

8 BY MR. RIPLEY:

9 Q Would you please state your full name for the

10 record?

11 A Yes. My name is Dennis E. Peseau, spelled

12 P-e-s-e-a-u.

13 Q And your business address?

14 A Is 1500 Liberty Street, Suite 250, Salem,

15 Oregon.

16 Q Did you have cause to be prepared for this

17 proceeding certain prefiled testimony consisting of 18

18 pages and within that testimony you sponsored and

19 identified Exhibits 25 through 28 -- excuse me, 25 through

20 27?

21 A Yes.

22 Q And if I asked you the questions that are set

23 forth in your prefiled testimony today, would your answers

24 be the same?

25 A They would.

517

CSB REPORTING PESEAU (Di-Reb)
Wilder, Idaho 83676 Idaho Power Company

1 Q Do you have any changes to your testimony

2 and/or exhibits?

3 A I have one to the testimony. On page 10,

4 line 17, the second to the last word should be "is," not

5 "as." That's all the corrections I have.

6 Q With the exception of that correction, if I

7 asked you -- I think I already said that -- would your

8 answers be the same?

9 A Yes, they would.

10 MR. RIPLEY: We would request that the

11 testimony of Dr. Peseau be spread upon the record as if

12 read and his exhibits be identified as marked in his

13 prefiled testimony and we'd tender him for

14 cross-examination.

15 MR. RICHARDSON: Mr. Chairman?

16 COMMISSIONER KJELLANDER: Yes.

17 MR. RICHARDSON: I have an objection to the

18 admission of Dr. Peseau's testimony.

19 MR. RIPLEY: Oh.

20 COMMISSIONER KJELLANDER: Well, let's hear

21 it.

22 MR. RICHARDSON: The basis of my objection is

23 that Dr. Peseau's testimony is not trustworthy, is not

24 credible and is not the type of evidence upon which a

25 reasonable person may rely. May I inquire some questions

518

CSB REPORTING PESEAU (Di-Reb)
Wilder, Idaho 83676 Idaho Power Company

1 of Dr. Peseau to lay the foundation for my objections?

2 COMMISSIONER KJELLANDER: Certainly.

3 MR. RICHARDSON: Dr. Peseau, are you being

4 paid for your testimony here today?

5 THE WITNESS: Yes, I am.

6 MR. RICHARDSON: Did you write this

7 testimony?

8 THE WITNESS: Yes, I did.

9 MR. RICHARDSON: When?

10 THE WITNESS: Well, over a period of a few

11 weeks prior to the filing date.

12 MR. RICHARDSON: And the filing date was

13 August 7?

14 THE WITNESS: That could be, yes.

15 MR. RICHARDSON: Did Idaho Power tell you

16 what to put in your testimony?

17 THE WITNESS: No, they did not.

18 MR. RICHARDSON: So your testimony is

19 reflective of your professional unbiased opinion; correct?

20 THE WITNESS: Yes.

21 MR. RICHARDSON: And you conclude in your

22 prepared testimony, in your proffered testimony, at

23 page 15, lines 16 through 20 that basing the transfer price

24 for operating book purposes on the independent, objective,

25 fluid and arms-length transactions calculated by the Mid-C

519

CSB REPORTING PESEAU (Di-Reb)
Wilder, Idaho 83676 Idaho Power Company

1 index remove all questions of whether these transactions

2 are prudently priced; correct?

3 THE WITNESS: Correct.

4 MR. RICHARDSON: Mr. Chairman, may I approach

5 the witness?

6 COMMISSIONER KJELLANDER: For what purpose?

7 MR. RICHARDSON: To show the witness a

8 document to refresh his memory.

9 COMMISSIONER KJELLANDER: Do you have that

10 document to share with --

11 MR. RICHARDSON: I do, Mr. Chairman.

12 COMMISSIONER KJELLANDER: Please do so.

13 (Mr. Richardson approached the witness.)

14 COMMISSIONER KJELLANDER: And,

15 Mr. Richardson, since the Commission does not have the

16 benefit of seeing a copy of what you've just handed, please

17 describe it.

18 MR. RICHARDSON: Thank you, Mr. Chairman.

19 I'll lay the foundation for the document now. Dr. Peseau,

20 do you recognize this document?

21 THE WITNESS: Yes, I do.

22 MR. RICHARDSON: Can you please identify it

23 for us?

24 THE WITNESS: They are handwritten notes in

25 my handwriting to you of November 17, the year 2000.

520

CSB REPORTING PESEAU (Di-Reb)
Wilder, Idaho 83676 Idaho Power Company

1 MR. RICHARDSON: And when you prepared this

2 document, were you employed by the Industrial Customers of

3 Idaho Power?

4 THE WITNESS: Yes.

5 MR. RICHARDSON: Okay, Dr. Peseau, would you

6 read the first bullet point on the first page from this

7 document?

8 MR. RIPLEY: Well, first let me say that

9 Mr. Richardson is asking that the testimony be struck, not

10 that he be permitted to cross-examine the voracity of the

11 Company's witness. Getting into what this memo says does

12 not lead one to the conclusion that the testimony should be

13 struck. That's the current motion before the Commission, I

14 believe.

15 MR. RICHARDSON: Mr. Chairman, this document

16 is evidence of prior inconsistent statements by the witness

17 which are proper foundation for a motion to strike and in

18 order for you to understand that he's made these prior

19 inconsistent statements, you need to hear what they say.

20 MR. RIPLEY: I do not believe that prior

21 inconsistent statements give rise to the ability of the

22 Commission to strike testimony. It certainly goes to the

23 weight of that testimony. When we get into it, I have no

24 problem with the witness addressing all of these concerns,

25 but I think procedurally, it's simply out of order to move

521

CSB REPORTING PESEAU (Di-Reb)
Wilder, Idaho 83676 Idaho Power Company

1 to strike on the basis that counsel believes he has a prior

2 inconsistent statement.

3 MR. RICHARDSON: Mr. Chairman, this document

4 shows prior inconsistent statements to the extent that it

5 casts a shadow on the trustworthiness and credibleness and

6 whether or not a reasonable person would rely on this

7 testimony and, therefore, it is not simply to impeach or

8 cast a shadow of doubt on the credibility of the witness,

9 it goes to the heart of the testimony whether it's

10 admissible or not.

11 COMMISSIONER KJELLANDER: Just a moment. I'm

12 going to go at ease and we'll be back with you in just a

13 moment.

14 (Pause in proceedings.)

15 COMMISSIONER KJELLANDER: We're back on the

16 record. Having had an opportunity to confer as a

17 Commission, the way that we're going to proceed with this

18 is to first sustain the objection that was put forward by

19 Mr. Ripley and then to deny Mr. Richardson's motion as it

20 was presented and allow the testimony to be spread and the

21 exhibits to be admitted.

22 (Idaho Power Company Exhibit

23 Nos. 25 - 27 were admitted into evidence.)

24 (The following prefiled rebuttal

25 testimony of Dr. Dennis Peseau is spread upon the record.)

522

CSB REPORTING PESEAU (Di-Reb)
Wilder, Idaho 83676 Idaho Power Company

1 Q. Please state your name and business address.

2 A. My name is Dennis E. Peseau. My business

3 address is Suite 250, 1500 Liberty Street, S.E., Salem,

4 Oregon 97302.

5 Q. By whom and in what capacity are you

6 employed?

7 A. I am the President of Utility Resources, Inc.

8 ("URI"). URI has consulted on a number of economic,

9 financial and engineering matters for various private and

10 public entities for more than twenty years.

11 Q. Does Exhibit 25 describe your background and

12 experience?

13 A. Yes.

14 Q. What is the subject of your rebuttal

15 testimony?

16 A. My firm has been asked by Idaho Power Company

17 to review the testimony filed by the Company, the Staff and

18 the Idaho Irrigation Pumpers Association in Case Nos. E-01-7

19 and E-01-11. My rebuttal testimony and comments in these

20 proceedings are from a regional and economic perspective.

21 My testimony is limited primarily to three subject areas:

22 1. Staff's conclusion that Mid-Columbia

23 ("Mid-C") price indexes are no longer appropriate measures

24 of transfer prices;

25 2. Staff's suggestion to implement a lower-

523

PESEAU, DI-REB 1
Idaho Power Company

1 of-cost or market of Idaho Power purchases and higher-of

2 cost or market for Company sales, in place of market

3 transfer prices, and its request to capture $51 million of

4 revenue from IES;

5 3. Staff's and the Irrigation Pumpers'

6 contention that Idaho Power's and IES' short and

7 longer-term power purchase portfolios ought to be closely

8 correlated, and in particular, that term purchases

9 generally result in lower power costs for the utility.

10 Q. Have you and your firm been active recently

11 in power purchase, resource planning and market pricing

12 issues throughout the western system coordinating council

13 (WSCC) region?

14 A. Yes, we have conducted numerous studies and

15 analyses on such issues in the western U.S. and elsewhere

16 for twenty-five years. Recently our firm has participated

17 in numerous resource planning, market index pricing,

18 transfer pricing, market term purchase, transmission access

19 and general deregulation studies throughout the western U.S.

20 As noted by Company witness Ms. Hoyd and Staff witness Ms.

21 Carlock, however, the importance of these issues has

22 significantly increased in the past five years. While I

23 will not repeat most of this history, I need to highlight

24 certain aspects of recent changes in western electric

25 wholesale markets, particularly with regard to the trend in

524

PESEAU, DI-REB 2
Idaho Power Company

1 electric wholesale prices and spot and longer-term

2 purchases, in order to put my comments on Ms. Carlock's and

3 Mr. Yankel's testimony in proper perspective.

4 Q. Please explain.

5 A. Prior to the implementation of competitive

6 wholesale markets in the electric utility industry,

7 regional utilities were required to build and otherwise

8 acquire long-term generation facilities sufficient to meet

9 their respective native load and reserve margin

10 requirements. Long-term purchase contracts were rare,

11 usually limited to resource-specific purchases and sales

12 from an excess capacity facility.

13 Utility-to-utility purchases and sales were

14 short-term and bilateral in nature due to lack of mandatory

15 transmission access. As there was no established market or

16 market price, transactions were generally at a share-the-

17 savings or cost-plus basis.

18 The clear direction of FERC toward its 1996

19 transmission open access and market based wholesale

20 transactions, plus anticipation of similar provisions at the

21 retail level by state jurisdictions, completely transformed

22 resource planning of most electric utilities. Due to the

23 perceived eventual requirements to divest or otherwise

24 separate the generation function of utilities from their

25 transmission and distribution functions, utilities were

525

PESEAU, DI-REB 3
Idaho Power Company

1 facing the risk of potential "stranded costs" arising from

2 the need to sell generating facilities at prices

3 potentially below the regulatory book value of such assets.

4 Q. What occurred in the industry as a result of

5 FERC's implementation of competitive wholesale markets, and

6 the emerging movement toward competition and open access at

7 the retail level?

8 A. The successful implementation of competitive

9 wholesale markets gave electric utilities an important and

10 advantageous access to numerous outside generation

11 resources, lessening the perceived need to commit to build

12 internal generation. The advent of retail competition and

13 the corresponding risk of incurring stranded costs further

14 incented utilities to rely on wholesale market purchases,

15 avoiding construction of new generating facilities.

16 Thus the opening of the wholesale markets in

17 1996 led to a virtual explosion of wholesale transactions

18 and the establishment of independent, fluid and objective

19 "market centers" upon which indices could be established

20 for pricing purposes.

21 Q. What was the level and trend of wholesale

22 market prices in 1996 and thereafter in the western U.S.?

23 A. The level and trend of wholesale market

24 prices during the period since 1996 is important, in my

25 opinion, in understanding the context of my criticisms of

526

PESEAU, DI-REB 4
Idaho Power Company

1 Staff witness Ms. Carlock's giving up on the Mid-C pricing

2 index as a valid, accurate and correct basis upon which to

3 establish transfer prices between Idaho Power and IES.

4 As similarly occurred when natural gas

5 deregulated in the 1980s, electric wholesale prices

6 beginning in 1996 in the western United States fell far

7 below previous incremental resource costs and, in fact,

8 fell well below prior average power costs. This trend is

9 shown on my Exhibit 26. The two important points that are

10 reflected in the exhibit are first, the long period of low

11 prices, and second, this long trend of low prices was also

12 accompanied by low price volatility.

13 Q. What impacts on utility resource planning

14 resulted from the trend of low, stable wholesale prices?

15 A. Utilities relied more heavily on wholesale

16 transactions. Utilities also concluded that the low price

17 volatility made short-term purchases more advantageous than

18 long-term purchases.

19 MID-C PRICES AS APPROPRIATE TRANSFER PRICES

20 Q. Have you read Staff's testimony with regard

21 to the appropriateness of using Mid-C as a basis for

22 setting transfer prices for transactions between Idaho

23 Power and IES?

24 A. Yes. This issue is raised primarily in the

25 testimony of Ms. Carlock.

527

PESEAU, DI-REB 5
Idaho Power Company

1 Q. What is Staff's position with respect to

2 using the Mid-C index for transfer pricing?

3 A. It is my understanding that Staff once agreed

4 that the Mid-C index was a reasonable, objective, and

5 independent measure of market prices and, therefore,

6 appropriate to use as a transfer price. As I read Staff's

7 case, this support ended upon its audit in the April 1,

8 2000 - February 28, 2001 PCA case. Staff now proposes to

9 transfer approximately $51 million of revenues from

10 shareholders to ratepayers by rejecting the Mid-C index of

11 market prices in favor of its after-the-fact determination

12 to use the lower-of-cost or market for purchases by Idaho

13 Power and the higher-of-cost and market for sales by Idaho

14 Power.

15 Q. What will your comments address with respect

16 to Staff's position on the Mid-C index?

17 A. First, let me state that I am aware of the

18 procedural and legal arguments surrounding whether certain

19 agreements were or were not actually in effect and, as I am

20 not a lawyer, I have no comments in this regard.

21 My comments are limited to the merits of

22 Staff's position that something happened recently to the

23 Mid-C index that made it unworkable as a basis for transfer

24 pricing in the period April 1, 2000 - February 28, 2001.

25 Q. What conclusions have you reached with the

528

PESEAU, DI-REB 6
Idaho Power Company

1 issue of the mid-c index as measure of market price?

2 A. As explained in more detail by other Company

3 witnesses, throughout the period in question, Mid-C

4 remained a very fluid, independent, objective and accurate

5 indicator of market prices for all transactions occurring

6 in the Pacific Northwest. I do not at all agree with

7 Staff's conclusion that this Mid-C index somehow failed to

8 measure the terms under which arms-length transactions were

9 priced. In fact, I have found no instances were Staff has

10 even identified any shortcomings in the Mid-C index.

11 Q. What is the economic or technical basis for

12 staff's objection to the Mid-C index from April 1, 2000 -

13 February 28, 2001?

14 A. Staff, in their comments to the Commission

15 dated April 16, 2001, lists the three bases upon which it

16 was able to conclude for April 1999 - March 2000 that the

17 Mid-C price was acceptable:

18 1. The Mid-C price was independent.

19 2. The Mid-C price closely followed what

20 the Company was actually paying for power purchases and

21 charging for power sales.

22 3. The actual prices of the Company were

23 symmetrical and in a narrow band around Mid-C price index

24 for the months April 1999 through March 2000.

25 Q. Were any of the three market-pricing criteria

529

PESEAU, DI-REB 7
Idaho Power Company

1 acceptable to Staff in the period April 1999 - March 2000

2 not complied with in the period April 1, 2000 - February

3 28, 2001?

4 A. No. In fact these criteria were strictly met

5 in the period April 1, 2000 - February 28, 2001:

6 1. The Mid-C price remained independent.

7 2. The Mid-C price equaled what the Company

8 was actually paying for power purchases and charging for

9 power sales.

10 3. The actual prices of the Company were

11 exactly equal to the Mid-C price index for the months

12 April 1, 2000 - February 28, 2001.

13 Staff's conclusion that the Mid-C no longer

14 is reflective of prices paid for power purchases or

15 received for power sales by Idaho Power/IES is factually

16 quite incorrect. The Mid-C price is exactly reflective of

17 prices paid for and received from Idaho Power transactions.

18 These same Mid-C prices may or not be reflective of IES

19 transactions depending upon the degree of success or

20 failure that IES realizes in its risk taking.

21 I conclude that the Mid-C index worked just

22 as it was intended to work. All the market volatility and

23 risk was transferred to IES, as was the reward. What did

24 happen was that unprecedented market price volatility began

25 during the latter period of the 2000-2001 PCA year. During

530

PESEAU, DI-REB 8
Idaho Power Company

1 periods of market price volatility, the band of prices of

2 IES could be expected to not follow a narrow band around

3 the Mid-C average. Ultimately the extreme price volatility

4 that occurred during heavy system purchasing months caused

5 Idaho Power to file its PCA earlier this year in order to

6 help with utility cash flow and to get a price signal out

7 to its customers.

8 Q. Was there in fact significantly more market

9 price volatility in this last PCA year?

10 A. Yes. While visual inspection of prices shown

11 in my Exhibit 26 appear to support this, Exhibit 27

12 summarizes statistical data termed "analysis of variance."

13 The statistics on this exhibit verify that significant

14 increases in both the level and volatility occurred in the

15 2000-2001 PCA year.

16 Q. What does Exhibit 27 show?

17 A. Exhibit 27 compares statistically the means

18 (averages) and variance (volatility) for the prices on high

19 load, low load, and flat periods for these market indexes:

20 The Mid-C, the Palo Verde (PV) and the California-Oregon

21 border (COB). I present the results for all three market

22 centers to demonstrate that the Mid-C index during or

23 before the 2000-2001 PCA year did not somehow change as an

24 accurate basis for setting transfer prices, as suggested in

25 Staff testimony.

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Idaho Power Company

1 The statistical tests are the same for each

2 market index. The entire time period for which I report

3 the price data, June 1999 - March 2001, is broken into two

4 equal eleven month periods, June 1999 - April 2000 and May

5 2000 - March 2001. Exhibit 26 verifies visually the intent

6 of these statistical tests: to establish whether

7 significant differences do indeed exist between the earlier

8 period of relatively flat prices and the more recent period

9 of rising, volatile prices.

10 The summary statistics, namely the F-

11 statistics, do verify that significant differences exist

12 between the averages and volatility of prices between the

13 two periods in each of the three market indexes. I conclude

14 that all three indexes were reflecting on a consistent basis

15 the price volatility that led to the divergences and wider

16 than previous band of prices around each of the three price

17 indexes. The wider band of actual prices paid by IES is

18 not a product of any alleged failure of the Mid-C price

19 index during the period of the 2000-2001 PCA year.

20 Q. Does this increased, or for that matter, any

21 decreased volatility of market prices in any way make the

22 Mid-C index more or less useful as an appropriate transfer

23 price?

24 A. No, not at all. This Mid-C index, as

25 discussed by others, is a weighted average of numerous

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PESEAU, DI-REB 10
Idaho Power Company

1 transactions occurring during a consistent period of time

2 (hour, day, month, etc.). The fact that more volatility

3 occurs in a period of time does not reduce the value of the

4 index calculation.

5 The Mid-C index reflects an average

6 transaction price during a period in which approximately

7 50% of the transactions have been made "above market" and

8 50% below. For transactions closed at the Mid-C index,

9 approximately 50% beat the market and 50% are in excess of

10 the market. The value to Idaho Power and its ratepayers of

11 using the Mid-C index is that this deemed indexed price is

12 better for ratepayers than the price received by 50% of the

13 market participants, but at no risk. To be sure, Idaho

14 Power and its ratepayers are in a sense giving up the

15 opportunity to take on more risk by attempting to transact

16 in the 50% of below market average transactions.

17 Q. What, in your opinion, was the purpose of

18 using a single indexed price booking operating and non-

19 operating transactions?

20 A. There are two reasons. One is to establish,

21 in Staff's terms, a "pricing mechanism." The second is to

22 establish a pricing mechanism that is incapable of being

23 manipulated for purposes of taking advantage of a

24 transaction between regulated and unregulated functions.

25 Only a price mechanism based on a market

533

PESEAU, DI-REB 11
Idaho Power Company

1 index fulfills both purposes. I simply disagree that Mid-C

2 no longer represents a surrogate price for system power

3 transactions.

4 Q. Staff contends that "Substantially greater

5 margins on similar transactions for a non-regulated entity

6 compared to a regulated entity is an indicator of an

7 improper pricing mechanism." [Ms. Carlock, Direct, pages

8 24-25.] Mr. Yankel supports this concept as well. Do you

9 agree?

10 A. No. Margins on a transaction reflect the

11 degree of risk assumed. As I explained above, the Mid-C

12 pricing mechanism for Idaho Power and ratepayers is

13 designed to reduce risk and speculation on the part of the

14 regulated utility. The 50% potential upside for beating

15 the market is traded away for not having to experience the

16 downside of paying the above-market average.

17 THE $51 MILLION ADJUSTMENT

18 Q. What is the issue with respect to Staff's

19 proposed $51 million adjustment to PCA costs?

20 A. My understanding is that Staff no longer

21 agrees that the Mid-C price index serves as an appropriate

22 transfer price for transactions in the system's operating

23 book. This dissatisfaction leads Staff to adopt an

24 alternative transfer price that attributes to Idaho Power

25 "the lower-of-cost or market" to Company purchases from IES

534

PESEAU, DI-REB 12
Idaho Power Company

1 and "the higher-of-cost or market to Company sales." Since

2 the effect of Staff's proposal is to allocate 100% of all

3 non-operating profits on Idaho Power's transactions to

4 ratepayers, and 100% of all IES non-operating losses made on

5 Idaho Power transactions to IES, an adjustment calculated

6 to be $51 million in favor of ratepayers is proposed.

7 Q. Are there distinctions made between the types

8 of re-priced transactions comprising the $51 million?

9 A. I understand that of the $51 million proposed

10 adjustment, $3.6 million is based on real-time transactions

11 and the remaining $47.4 million is based on day-ahead

12 transactions. As I have not followed completely the basis

13 for the repricing of real-time transactions, my comments

14 here are limited to day-ahead transactions.

15 Q. Does Staff's proposed $51 million adjustment

16 have implications for the risk and uncertainty facing

17 IDACORP shareholders?

18 A. Yes. The direct testimony of Dennis Gribble

19 elaborates on the obvious income and financial implications

20 of a $51 million write-off. I want to place Staff's

21 proposed repricing adjustment in terms of risk and reward.

22 The Company's treatment of operating book

23 transactions in the PCA case continues its understanding of

24 the rules of the game: Idaho Power on behalf of ratepayers

25 receives an objective measure of market price for all

535

PESEAU, DI-REB 13
Idaho Power Company

1 transactions. This continuation of market-priced

2 transactions removes for ratepayers two aspects of risk:

3 the financial risk of transacting above and below market

4 prices for purchases and sales, respectively, and the risk

5 of potential abuse between the operating and non-operating

6 functions. Staff in the 1999-2000 PCA was in full

7 agreement at the time that eliminating these two sources of

8 risk was good for ratepayers.

9 In both the 1999-2000 and the 2000-2001 PCA

10 cases, IDACORP management assumed that eliminating these

11 sources of risk for Idaho Power left it free to undertake

12 substantially riskier positions in the wholesale power

13 markets on behalf of shareholders. IDACORP's assumptions

14 in this regard proved accurate in the 1999-2000 PCA case

15 and shareholders were attributed the gains and losses made

16 on its operating and non-operating transactions. These

17 same assumptions are not accurate in the 2000-2001 PCA case

18 according to Staff.

19 Q. Who was at financial risk for these

20 transactions?

21 A. Shareholders were at risk, since Idaho Power

22 was allowed the Mid-C transfer price.

23 Q. Did shareholders actually incur the financial

24 risk on their investment in the operating transactions?

25 A. Yes. Again, by virtue of Idaho Power

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PESEAU, DI-REB 14
Idaho Power Company

1 receiving the Mid-C market transfer price, shareholders

2 were entirely at risk for the outcome of the operating

3 transactions.

4 Q. Does Staff's proposal to reprice the

5 operating book transactions to reduce shareholder gain

6 misalign the risk and reward of these transactions?

7 A. Yes. In fact, Staff's proposal really

8 amounts to confiscation of shareholder property. The

9 financial obligation of the regulator to consider and align

10 shareholder returns commensurate with the risk undertaken

11 and in line with comparable other investment opportunities

12 is well established in prior legal proceedings such as the

13 Bluefield and Hope cases.

14 Q. In your opinion is there an issue of prudency

15 in the $51 million adjustment proposed by Staff?

16 A. No. Basing the transfer price for operating

17 book purposes on the independent, objective, fluid and

18 arms-length transactions calculated by the Mid-C index

19 remove all questions of whether these transactions are

20 prudently priced.

21 Q. If in the next PCA case there are $51 million

22 in transactional losses when measured against the Mid-C

23 index, how would the loss be treated?

24 A. Under the Company's continuation of existing

25 policies, IDACORP shareholders would sustain the losses and

537

PESEAU, DI-REB 15
Idaho Power Company

1 ratepayers would be insulated by virtue of Mid-C transfer

2 prices.

3 Under Staff's proposal in these proceedings,

4 we simply don't know. Staff's proposal here is carefully

5 worded to pertain only to these proceedings, not to future

6 cases. It is predicated on fixing the market price index

7 that, as I have testified, is not broken in the first place.

8 Q. What is your recommendation with respect to

9 Staff's proposed $51 million adjustment?

10 A. I recommend that the Commission continue with

11 use of the Mid-C transfer price in these proceedings and

12 deny the proposed $51 million adjustment.

13 LONG AND SHORT-TERM POWER TRANSACTIONS

14 Q. What is the issue in these proceedings with

15 respect to the length of terms for power transactions?

16 A. One issue raised in Staff testimony pertains

17 to whether short or longer-term purchase terms are least

18 costly. A second important issue raised by Staff is that

19 system operating book transactions for the 2000-2001 PCA

20 year were too heavily weighted to the short-term, allegedly

21 to the detriment of ratepayers.

22 Q. Are short-term or longer-term power purchases

23 least costly?

24 A. As acknowledged in the testimony of Staff

25 witness Mr. Lord, longer-term contracts introduce risk to

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PESEAU, DI-REB 16
Idaho Power Company

1 suppliers and therefore will command a premium over a

2 sequence of short-term purchases. I therefore disagree

3 with the latter half of Ms. Carlock's statement (direct,

4 page 8, lines 17-18) that "Term transactions reduce the price

5 variability and usually the cost for that time period..."

6 (Emphasis added). Usually, a sequence of short-term

7 purchases will be less costly than longer-term contracts,

8 although longer-term contracts obviously reduce price

9 volatility.

10 Q. Why do you raise this issue?

11 A. From my reading of Staff testimony (Carlock

12 direct, pages 7-8), I became concerned that Idaho Power

13 might be directed, apart from its own assessment of term

14 structures, to simply take long-term positions. While I do

15 not disagree that flexibility in balancing purchases of

16 different terms can at times be an important risk

17 management tool, this tool must remain entirely under the

18 purview of management. Longer-term positions as suggested

19 by Staff have recently proved financially disastrous to a

20 number of utilities.

21 Q. Please explain.

22 A. Utilities in the western U.S. that have

23 chosen to go long in purchases this past several months are

24 now facing two market developments that are proving to be

25 very costly. First, forward price curves have dropped

539

PESEAU, DI-REB 17
Idaho Power Company

1 dramatically in the last couple of months. Those utilities

2 that chose to lock in terms this past winter could have

3 reduced power costs significantly by postponing these long

4 positions. A second development was the April 26, 2001 FERC

5 Price Mitigation order effectively providing price caps to

6 transactions made throughout the WSCC. These price caps

7 have the effect of eliminating any profit opportunities of

8 utilities that went long at higher prices this last winter

9 in hope of selling off into higher-priced markets.

10 Our firm is involved in resource planning

11 proceedings for Southwest utilities that now face the

12 potential financial hardships of having entered longer-term

13 contracts this past winter.

14 Q. Is it your position that Idaho Power should

15 never enter into longer-term power contracts?

16 A. No, not at all. I am only pointing out that

17 management of contract purchase terms is very much a risk

18 management tool to be left up to the discretion of Idaho

19 Power. However, while the utility must make the risk

20 management decisions, the Company must be able to rely on

21 some ongoing regulatory rules under which to base its

22 decisions.

23 Q. Does this conclude your rebuttal testimony?

24 A. Yes, it does.

25

540

PESEAU, DI-REB 18
Idaho Power Company

1 (The following proceedings were had in

2 open hearing.)

3 COMMISSIONER KJELLANDER: And we will now

4 turn to Mr. Richardson to proceed.

5 MR. RICHARDSON: Thank you, Mr. Chairman.

6

7 CROSS-EXAMINATION

8

9 BY MR. RICHARDSON:

10 Q Dr. Peseau, at page 15 of your testimony, you

11 conclude that basing the transfer price for operating book

12 purposes under what you termed independent, objective,

13 fluid and arms-length transactions calculated by the Mid-C

14 index removes all questions of whether these transactions

15 are prudently priced; correct?

16 A That's correct.

17 Q Would you agree with the statement that the

18 proposed Idaho Power/IES relationship, that structure

19 allows for no market test for reasonableness as it does not

20 contemplate competing bids and, therefore, is not in the

21 ratepayer's best interests?

22 MR. RIPLEY: To which we would object. If

23 counsel desires to bring this up in IPC-E-01-16, he has

24 every right to do so. This is IPC-E-01-7 and 11 and the

25 IES/Idaho Power agreement insofar as it's related to the

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Wilder, Idaho 83676 Idaho Power Company

1 pricing of Mid-C is irrelevant.

2 MR. RICHARDSON: Mr. Chairman, Dr. Peseau's

3 testimony speaks to the prudency of the use of the Mid-C

4 index for pricing transactions. The question I asked goes

5 directly to that issue, is it prudent to use the Mid-C

6 index as a method for prudently pricing the transactions

7 and the question I asked is whether or not accepting

8 competing bids cures a problem with that prudency. It goes

9 directly to Dr. Peseau's testimony.

10 COMMISSIONER KJELLANDER: I will allow the

11 question.

12 THE WITNESS: The testimony on page 15 refers

13 to a transfer price, that is, a fair and objective, fluid

14 price by which power transfers may be made between the

15 operating and non-operating entities. The first paragraph

16 of this paper that you read talks about the proposed

17 business structure between IPC and IES that was proposed at

18 the time. As I recall, IES was proposing to charge Idaho

19 Power a fixed annual fee. I don't recall what that fee

20 was. This point says unless you go to bid, you don't know

21 that IES is bidding the lowest bid to transact. It has

22 nothing do with Mid-C. It has nothing to do with transfer

23 pricing.

24 Q BY MR. RICHARDSON: Would you agree that the

25 relationship between IPC and IES and the existing PCA

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1 removes incentives for least cost purchases of power for

2 retail customers and provides incentives to pay excess over

3 least cost to IES as each entity has the same stock owners,

4 IDACORP, and these perverse incentives do not exist if a

5 third party conducts the proposed IES functions?

6 A Absent a market fluid, independent measure of

7 a transfer price, that could be true.

8 Q So we have perverse incentives here?

9 A Only if we have a cost-calculated transfer

10 price. If we have a Mid-C or another objective,

11 independent price to transfer, then you remove the perverse

12 incentives. That's the whole theory behind using Mid-C.

13 Q Isn't the Staff's proposal in this case to do

14 least cost of market or index and isn't that exactly where

15 we're going with perverse incentives, to prevent those

16 incentives, to charge an index when perhaps there's a lower

17 cost available to charge?

18 A There's always a lower cost to charge, but it

19 doesn't mean that it's in any sense fair. Once we use a

20 market price index, Mid-C, we remove perverse incentives.

21 Staff's proposal now is to depart from its previously

22 determined conclusions that the Mid-C was an appropriate

23 pricing index and now look back over the most recent PCA

24 test year and say that an actual cost because it's lower

25 than Mid-C is the appropriate. That doesn't remove any

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CSB REPORTING PESEAU (X-Reb)
Wilder, Idaho 83676 Idaho Power Company

1 perverse incentives. In fact, it creates a whole lot of

2 perverse incentives.

3 Q A Staff witness talked a lot about oversight

4 and appropriate safeguards and ability to audit and

5 monitor, there's been a lot of discussion of that in this

6 hearing, would you agree that all provisions for auditing

7 are meaningless in light of the necessity for professional

8 commodity traders generally in scarce supply and able to be

9 high remunerated not available to Staff to conduct such

10 audits?

11 A I said that and I continue to think that if

12 we move off of an appropriate pricing index and instead

13 move to audits of actual costs and attempted calculations

14 of costs between the op and the non-op, that's the very

15 reason in the 1970s the Pacific Northwest Bell and all the

16 affiliate interest problems came to be in the first place.

17 This statement you just read goes to that issue. It was

18 prior to any knowledge I had of the implementation of an

19 objective Mid-C pricing index.

20 MR. RICHARDSON: That's all I have,

21 Mr. Chairman.

22 COMMISSIONER KJELLANDER: Let's move to the

23 Deputy Attorney General representing the IPUC Staff,

24 Ms. Nordstrom.

25 MS. NORDSTROM: Thank you.

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1 CROSS-EXAMINATION

2

3 BY MS. NORDSTROM:

4 Q Does a transaction for day-ahead versus

5 real-time pricing allow the application of the transfer

6 price to a different time period?

7 A Does it allow? It depends on the structure.

8 Could I have the question again?

9 Q Does a transaction for day-ahead versus

10 real-time pricing allow the application of the transfer

11 price to a different time period?

12 A That depends. I'm not sure whether you're

13 saying one locks into a day-ahead price and then reprices

14 it or does one decide on a day-ahead basis whether to

15 forego a day-ahead and then go to a real-time price.

16 Q The former.

17 A Then yes, it would by a day.

18 Q Do you believe the day-ahead Mid-C index

19 prices appropriately reflect Idaho border real-time prices?

20 A I don't have an opinion on that. I haven't

21 dealt with that.

22 Q On page 14 of your rebuttal testimony,

23 actually it's 14 and 15, you state that shareholders were

24 at risk for the 2000-2001 PCA case. Do you agree that both

25 ratepayers and shareholders bore the financial risk for the

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CSB REPORTING PESEAU (X-Reb)
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1 transactions that were taken during that time period?

2 A To the extent that the PCA costs are

3 authorized, then consumers will pay that, but ultimately

4 the question of prudence and so forth is ultimately the at

5 risk of the shareholders.

6 Q Is it correct to conclude that based on your

7 testimony you believe there was significant energy market

8 price volatility during the 2000-2001 PCA period?

9 A Yes, beginning towards the end of November of

10 2000 there was considerable volatility. There was some

11 movement prior to that.

12 Q Do you also agree that there was significant

13 price movement over many days during the year, within that

14 year?

15 A That's how volatility occurs, hour by hour,

16 day by day.

17 Q Would you agree that the day-ahead Mid-C

18 market price, the subject of this discussion in this case,

19 is a weighted average for heavy load hours and an average

20 for light load hours in a given 24-hour period?

21 A Yes.

22 Q Would you also agree that the more volatile

23 the price, for example, in the 16-hour high load period,

24 the greater variance existed between the 16-hour average

25 and individual transactions?

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CSB REPORTING PESEAU (X-Reb)
Wilder, Idaho 83676 Idaho Power Company

1 A I'm sorry, the last of that was that more

2 variability occurred when?

3 Q The price was more volatile when greater

4 variance existed between the 16-hour average and individual

5 transaction prices.

6 A The individual variance in the individual

7 prices is what gives rise to a measure of variance. I'm

8 trying to be responsive, but the greater the variance in

9 the individual prices the greater the measure of variance a

10 single statistic is if that's what you mean. Variances are

11 always higher the more variable individual prices are.

12 Q In the alternative, when prices during the

13 day are relatively stable, do you agree that the Mid-C

14 average will closely match individual transactions for that

15 particular day?

16 A The question is, is the variance of a

17 narrower band of prices less than the variance of a greater

18 band in prices, yes.

19 Q Thank you. In volatile markets where prices

20 change radically during a load period, would you agree that

21 there are drastic differences between daily averages and

22 the cost of individual transactions to say that another

23 way?

24 A There are differences. If you want to call

25 them drastic, I guess I would need an example as to how

547

CSB REPORTING PESEAU (X-Reb)
Wilder, Idaho 83676 Idaho Power Company

1 drastic, but they certainly can be significant and have

2 been.

3 Q Idaho Power's position is that the Mid-C is a

4 liquid and transparent trading location. Would this imply

5 that the costs of transaction are lowest at this point for

6 Idaho Power Company?

7 A No.

8 Q Why not?

9 A Because a liquid, independent market is just

10 that. We can have a liquid, independent market in Europe

11 for that matter and it wouldn't be cheaper. One is an

12 objective measure of what a market center is and there are

13 a number of those about the country, but it doesn't mean

14 that it's the lowest cost period.

15 Q I was referring to transmission costs,

16 transaction costs rather, not price.

17 A Transaction costs including -- I'm sorry,

18 transaction costs between bilateral contracts, transmission

19 costs and so forth?

20 Q Yes.

21 A I would expect on average that Mid-C prices

22 would be least cost to Idaho Power, but what makes me

23 nervous, that doesn't have anything to do with my

24 assessment of whether Mid-C it is an independent, fluid

25 market or not. It is.

548

CSB REPORTING PESEAU (X-Reb)
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1 Q Are there any other appropriate liquid and

2 fluid markets, trading locations out there for Idaho Power

3 to use?

4 A As a means to transfer, for transferring

5 power between op and non-op?

6 Q Yes.

7 A I don't know of any.

8 MS. NORDSTROM: May I have just a moment?

9 COMMISSIONER KJELLANDER: Yes.

10 (Pause in proceedings.)

11 Q BY MS. NORDSTROM: I think I just have one

12 last question for you. You agreed that the hedge allowed

13 them to shift time periods, this swap that we've been

14 discussing; is that correct?

15 A Well, we weren't discussing hedges or swaps.

16 We were talking about a day-ahead versus what I would

17 assume was the next day real-time price.

18 Q Correct. Would this shift in time periods

19 allow for the perverse incentives that you described

20 earlier?

21 A I'm sure you could construct some examples

22 where it might. That would, I think, argue for some ground

23 rules on that.

24 Q But the opportunity is there; is that

25 correct?

549

CSB REPORTING PESEAU (X-Reb)
Wilder, Idaho 83676 Idaho Power Company

1 A I don't have an example in mind, but I think

2 there could be. Any time you have an opportunity to shift

3 price for a commodity, there may be an opportunity.

4 MS. NORDSTROM: Thank you. No further

5 questions.

6 COMMISSIONER KJELLANDER: Questions from the

7 Commission.

8 Commissioner Smith.

9

10 EXAMINATION

11

12 BY COMMISSIONER SMITH:

13 Q Yes, Doctor, did I understand your testimony

14 correctly in response to a question that you believe that

15 price movement began in November of 2000?

16 A I said the significant price movement began

17 in -- well, there are charts that I can refer to in the

18 last week in November, I believe.

19 Q So in your mind the price movements that

20 began earlier in the year were not significant?

21 A I suppose it depends on what side of the

22 transaction you are on, but relatively speaking, the price

23 movements from November through spring were far more

24 significant than any time before. We did have an April

25 through August price spike as well, but it was what now

550

CSB REPORTING PESEAU (Com-Reb)
Wilder, Idaho 83676 Idaho Power Company

1 looks to be pretty small, but it was considered significant

2 at the time. I'm not saying that it was insignificant by

3 any means.

4 COMMISSIONER SMITH: Thank you.

5 COMMISSIONER KJELLANDER: Are there further

6 questions from the Commission?

7 Commissioner Hansen.

8 COMMISSIONER HANSEN: I do have one.

9

10 EXAMINATION

11

12 BY COMMISSIONER HANSEN:

13 Q I'm trying to put it together so I may have

14 to ask it a couple of times. On page 2 of your testimony,

15 lines 14 through 19, you mention that you have been

16 involved with a variety of studies and so forth. I guess

17 my question would be, have you done any work in the last

18 year that would have helped utilities such as Idaho Power

19 Company in this case hedge against the enormous changes in

20 the wholesale market price in the West? I mean, you talk

21 about that you've done, could -- I guess what I'm asking

22 is, are there resources out there where they could have

23 come and got some help?

24 A The answer is yes to your question,

25 Commissioner. We have done work primarily in the

551

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1 Southwest, a lot of it in Nevada, and it's been primarily

2 in representing larger customers in resource planning

3 proceedings and in deferred energy proceedings to help add

4 some of the input that I think Mr. Simard was talking about

5 about what's the customer's appetite for risk. In a couple

6 of instances, Nevada Power and Avista in particular did

7 decide to hedge over a multi-month period and it turned out

8 to be unfortunate, so we're back at the table. Nevada

9 Power, for example, has deferred some -- they're

10 anticipating deferring some $700 million in costs as a

11 result of these hedges and I understand from the Avista

12 case that was filed here and in the State of Washington

13 that they're anticipating some 300 million, so we are not

14 in giving advice, certainly we're not proposing that

15 customers insist on long-term hedges.

16 Had a long-term hedge prior to November taken

17 place, looking back, it would have been helpful for a

18 period of a few months, but if we were into a hedge this

19 year, for example, right now with prices at $35.00, $40.00

20 a megawatt-hour, the hedge obviously is to the detriment,

21 significant detriment, of customers, so fortunately, we've

22 not taken any strong positions urging hedges or, for that

23 matter, urging short-term prices. It's difficult.

24 In the midst of all the turmoil in California

25 and in the midst of the significant lawsuits that we have

552

CSB REPORTING PESEAU (Com-Reb)
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1 that some people attribute to the price spike beginning in

2 November of 2000 and ending in spring, until these market

3 imperfections are worked out, I think we would be

4 increasing risk rather than decreasing it by suggesting

5 rules of hedging. It's a very delicate and very risky

6 game.

7 Q So then to just kind of summarize, you've

8 done a lot of studies and analyses in the Southwest and so

9 forth, but you really haven't come up with any great

10 direction or advice to give utilities that need help in

11 this area; is that right?

12 A Yeah, I certainly have had enough

13 mathematical statistics to believe that commodity prices,

14 and I include electricity there, are essentially a random

15 walk and you need more than forecasts of prices, because

16 they're often wrong, to place a lot of bets. You need a

17 lot of trading abilities and ways to make money over and

18 above just taking a price position and over time when you

19 have a random walk for prices, you just need to do other

20 things.

21 I think Mr. Simard's points about at least

22 getting a consensus or some input so that the utilities

23 don't feel that any risk they take on they will be

24 compensated for is certainly a first step in that

25 direction, but if your question is what would I propose

553

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1 that Idaho Power do over the next year, I just don't have

2 an answer for that.

3 COMMISSIONER HANSEN: Thank you.

4 COMMISSIONER KJELLANDER:

5 Commissioner Smith.

6

7 EXAMINATION

8

9 BY COMMISSIONER SMITH:

10 Q So are you aware that the Commission approved

11 an irrigation buy-back program?

12 A Yes.

13 Q Do you think that's a hedge?

14 A It is.

15 COMMISSIONER SMITH: Thank you.

16 COMMISSIONER KJELLANDER: We're ready now for

17 redirect.

18

19 REDIRECT EXAMINATION

20

21 BY MR. RIPLEY:

22 Q Doctor, if I could direct your attention to

23 Exhibit 26, your Exhibit 26.

24 A Yes.

25 Q Commissioner Smith asked you some questions

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Wilder, Idaho 83676 Idaho Power Company

1 regarding price. Looking at that exhibit, could you

2 provide her with additional information as to what occurred

3 in pricing from June of '99 through March of '01?

4 A Yes, I was talking about an exhibit --

5 COMMISSIONER SMITH: Mr. Ripley, I know what

6 occurred. I guess I was inquiring as to what he considered

7 to be significant.

8 MR. RIPLEY: I misinterpreted your question

9 and I apologize. No need to answer my question.

10 THE WITNESS: Okay.

11 MR. RIPLEY: With that, I have no -- you've

12 just run a knife through my heart. I have no additional

13 redirect.

14 (The witness left the stand.)

15 COMMISSIONER KJELLANDER: I guess in the

16 absence of stopping the bleeding, then, as we had at least

17 mentioned getting into this afternoon -- and you're excused

18 Mr. Peseau -- I guess we're at a breaking point, then, for

19 the day, if I'm not mistaken; is that correct?

20 MR. RIPLEY: Yes, sir.

21 COMMISSIONER KJELLANDER: Okay, and it's then

22 the intent to start up early in the morning and you hope to

23 have any changes in your rebuttal testimony in a Q and A

24 format and to the extent that that can be delivered to the

25 intervenors in appropriate fashion, that would be extremely

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1 helpful.

2 I think the only thing left for us to decide

3 at this point really is the time at which we'd like to

4 reconvene tomorrow and would 9:00 o'clock be an appropriate

5 start time? We'll shoot for 9:00 o'clock and that's really

6 the time that I think I would like to start tomorrow.

7 MS. NORDSTROM: Mr. Chairman?

8 COMMISSIONER KJELLANDER: Yes.

9 MS. NORDSTROM: Will Staff and intervenors

10 have an opportunity to review this new testimony and

11 exhibits prior to beginning at 9:00 o'clock?

12 COMMISSIONER KJELLANDER: It would be my

13 hope, but, again, it depends on how long it takes for them

14 to put their testimony together, so for me to try and sit

15 here today and mandate that it must be given to you by a

16 certain time and point during this day or early tomorrow, I

17 don't think I could fairly do that to the Company. It

18 would be my hope that in the essence of fairness that that

19 be made available to you as soon as it's reasonable for

20 that to occur.

21 MS. NORDSTROM: Thank you.

22 COMMISSIONER KJELLANDER: So at this point

23 what we would do is adjourn for the day with the intent to

24 reconvene tomorrow morning at 9:00.

25 (The Hearing recessed at 2:45 p.m.)

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